Processes and systems for petrochemical production integrating coking and deep hydrogenation of coking reaction products

ABSTRACT

A feedstock is processed in a coking zone unit to produce at least light gases, coker naphtha, light coker gas oil and petroleum coke. Light coker gas oil, and in certain embodiments hydrotreated light coker gas oil, is subjected to deep hydrogenation to produce a deeply hydrogenated middle distillate fraction. All or a portion of the deeply hydrogenated middle distillate fraction is used as feed to the stream cracking zone to produce light olefins.

RELATED APPLICATIONS

Not applicable.

BACKGROUND OF THE INVENTION Field of the Invention

The inventions disclosed herein relate to deep hydrogenation of middledistillates for conversion into feedstocks suitable for steam crackingto produce light olefins, and an integrated process and system forconverting crude oil to petrochemicals integrating deep hydrogenation ofmiddle distillates.

Description of Related Art

Processing options for crude oil fractions are typically as follows:light naphtha streams from crude oil distillation and/or from otherprocessing units are sent to an isomerization unit to convertstraight-chain paraffins into isomers which have higher octane numbersto produce gasoline blending component; heavy naphtha streams from crudeoil distillation, coker, and cracking units are fed to a catalyticreformer to improve octane numbers, and products from the catalyticreformer can be blended into regular and premium gasolines formarketing; middle distillates from the crude oil distillation and otherprocessing unit are blended into diesel fuels, jet fuels and/or furnaceoils, directly or following hydrotreating to obtain ultra-low sulfurdiesel; vacuum gas oil is hydrocracked to produce diesel or fluidcatalytically cracked to obtain gasoline; the vacuum residue fractioncan be subjected to hydroprocessing, delayed or fluid coking, thermalcracking, solvent deasphalting, gasification, or visbreaking.

Conventional refineries are designed and built to produce transportationfuels such as gasoline and diesel. With the increasing demand for lightolefins such as ethylene and propylene as chemical building blocks, andincreasing cost of conventional feedstocks, refiners and petrochemicalproducers are exploring new processing options to convert crude oil toproduce light olefins and aromatics. In atypical refinery, the naphthastream is typically hydrotreated to remove sulfur and nitrogen and thensent to a catalytic reforming unit to produce gasoline.

In refineries integrating light olefin production, one or more naphthastreams are routed to a steam cracking complex to produce light olefins.The lower olefins (i.e., ethylene, propylene, butylene and butadiene)are basic intermediates which are widely used in the petrochemical andchemical industries. Thermal cracking, or steam pyrolysis, is a majortype of process for forming these materials, typically in the presenceof steam, and in the absence of oxygen. In such refineries, middledistillates are typically fractioned between a kerosene range fractionand a diesel range fraction to produce jet fuels and diesel/furnace oilfuels, respectively. For instance, a diesel range fraction is subjectedto hydrotreating, typically followed by other hydroprocessing to producediesel fuels and/or furnace oils.

A need remains in the art for improved processes for converting crudeoil to basic chemical intermediates such as lower olefins. In addition,a need remains in the art for new approaches that offer higher valuechemical production opportunities with greater leverage on economies ofscale.

SUMMARY

In accordance with one or more embodiments, a system and process areprovided for deep hydrogenation of hydrotreated middle distillates toproduce an effluent that is suitable as a feedstock to a steam crackingcomplex.

In accordance with one or more embodiments, the invention relates to anintegrated process for producing petrochemicals. A suitable feedstock isprocessed in a coking unit to produce at least light gases, cokernaphtha, light coker gas oil, heavy coker gas oil, and coke. Light cokergas oil, and in certain embodiments hydrotreated light coker gas oil issubjected to deep hydrogenation to produce a deeply hydrogenated middledistillate fraction. All or a portion of the deeply hydrogenated middledistillate fraction is used as feed to the stream cracking zone, toproduce lower olefins, pyrolysis gasoline and pyrolysis oil. Theproducts from the steam cracking zone H₂, methane, ethane, ethylene,mixed C3s and mixed C4s; pyrolysis gasoline stream(s); and pyrolysis oilstream(s). From the mixed product stream(s) C3s and the mixed C4s,petrochemicals ethylene, propylene and butylenes are recovered. Ethaneand non-olefinic C3s are recycled to the steam cracking zone, andnon-olefinic C4s are recycled to the steam cracking zone or to aseparate processing zone for production of additional petrochemicals.

Still other aspects, embodiments, and advantages of these exemplaryaspects and embodiments, are discussed in detail below. Moreover, it isto be understood that both the foregoing information and the followingdetailed description are merely illustrative examples of various aspectsand embodiments, and are intended to provide an overview or frameworkfor understanding the nature and character of the claimed aspects andembodiments. The accompanying drawings are included to provideillustration and a further understanding of the various aspects andembodiments, and are incorporated in and constitute a part of thisspecification. The drawings, together with the remainder of thespecification, serve to explain principles and operations of thedescribed and claimed aspects and embodiments.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be described in further detail below and withreference to the attached drawings in which the same or similar elementsare referred to by the same number, and where:

FIG. 1 schematically depicts an embodiment of a process for producingpetrochemicals and fuel products integrating coking of certain feedswithin a refinery system and a steam cracker complex;

FIG. 2A schematically depicts an embodiment of a process for producingpetrochemicals and fuel product integrating coking of certain feedswithin a refinery system and a steam cracker complex, and including deephydrogenation of light coker gas oil;

FIG. 2B schematically depicts an embodiment of a process for producingpetrochemicals and fuel product integrating coking of certain feedswithin a refinery system and a steam cracker complex, and including deephydrogenation of light coker gas oil and hydrogenation of naphtha;

FIG. 3 schematically depicts another embodiment of a process forproducing petrochemicals and fuel product integrating coking and a steamcracker complex, and including deep hydrogenation of light coker gasoil;

FIGS. 4, 5 and 6 schematically depicts coking operations suitable foruse in embodiments herein; and

FIG. 7 schematically depicts an embodiment of a steam cracker complexincluding a middle distillate steam cracking section and a naphtha steamcracking section.

DESCRIPTION

Process scheme configurations are disclosed that enable conversion ofcrude oil feeds with several processing units in an integrated mannerinto petrochemicals. The designs utilize minimum capital expenditures toprepare suitable feedstocks for the steam cracker complex. Theintegrated process for converting crude oil to petrochemical productsincludes steam cracking of deeply hydrogenated middle distillatefractions. Feeds to the steam cracker are derived from straight runmiddle distillates, and one or more middle distillate fractions fromhydroprocessing zones within the battery limits.

The phrase “a major portion” with respect to a particular stream orplural streams means at least about 50 wt % and up to 100 wt %, or thesame values of another specified unit.

The phrase “a significant portion” with respect to a particular streamor plural streams means at least about 75 wt % and up to 100 wt %, orthe same values of another specified unit.

The phrase “a substantial portion” with respect to a particular streamor plural streams means at least about 90, 95, 98 or 99 wt % and up to100 wt %, or the same values of another specified unit.

The phrase “a minor portion” with respect to a particular stream orplural streams means from about 1, 2, 4 or 10 wt %, up to about 20, 30,40 or 50 wt %, or the same values of another specified unit.

The term “crude oil” as used herein refers to petroleum extracted fromgeologic formations in its unrefined form. Crude oil suitable as thesource material for the processes herein include Arabian Heavy, ArabianLight, Arabian Extra Light, other Gulf crudes, Brent, North Sea crudes,North and West African crudes, Indonesian, Chinese crudes, or mixturesthereof. The crude petroleum mixtures can be whole range crude oil ortopped crude oil. As used herein, “crude oil” also refers to suchmixtures that have undergone some pre-treatment such as water-oilseparation; and/or gas-oil separation; and/or desalting; and/orstabilization. In certain embodiments, crude oil refers to any of suchmixtures having an API gravity (ASTM D287 standard), of greater than orequal to about 20°, 30°, 32°, 34°, 36°, 38°, 40°, 420 or 44°.

The acronym “LPG” as used herein refers to the well-known acronym forthe term “liquefied petroleum gas,” and generally is a mixture of C3-C4hydrocarbons. In certain embodiments, these are also referred to as“light ends.”

As used herein, all boiling point ranges relative to hydrocarbonfractions derived from crude oil via atmospheric and/or shall refer toTrue Boiling Point values obtained from a crude oil assay, or acommercially acceptable equivalent.

The term “naphtha” as used herein refers to hydrocarbons boiling in therange of about 20-220, 20-210, 20-200, 20-190, 20-180, 20-170, 32-220,32-210, 32-200, 32-190, 32-180, 32-170, 36-220, 36-210, 36-200, 36-190,36-180 or 36-170° C.

The term “light naphtha” as used herein refers to hydrocarbons boilingin the range of about 20-110, 20-100, 20-90, 20-88, 32-110, 32-100,32-90, 32-88, 36-110, 36-100, 36-90 or 36-88° C.

The term “heavy naphtha” as used herein refers to hydrocarbons boilingin the range of about 90-220, 90-210, 90-200, 90-190, 90-180, 90-170,93-220, 93-210, 93-200, 93-190, 93-180, 93-170, 100-220, 100-210,100-200, 100-190, 100-180, 100-170, 110-220, 110-210, 110-200, 110-190,110-180 or 110-170° C.

In certain embodiments naphtha, light naphtha and/or heavy naphtha referto such petroleum fractions obtained by crude oil distillation, ordistillation of intermediate refinery processes as described herein.

The term “middle distillates” as used herein relative to effluents fromthe atmospheric distillation unit or flash zone refers to hydrocarbonsboiling in the range of about 170-370, 170-360, 170-350, 170-340,170-320, 180-370, 180-360, 180-350, 180-340, 180-320, 190-370, 190-360,190-350, 190-340, 190-320, 200-370, 200-360, 200-350, 200-340, 200-320,210-370, 210-210, 210-350, 210-340, 210-320, 220-370, 220-220, 220-350,220-340 or 220-320° C.

The modifying term “straight run” is used herein having its well-knownmeaning, that is, describing fractions derived directly from theatmospheric distillation unit, optionally subjected to steam stripping,without other refinery treatment such as hydroprocessing, delayed cokingor steam cracking. An example of this is “straight run naphtha” and itsacronym “SRN” which accordingly refers to “naphtha” defined above thatis derived directly from the atmospheric distillation unit, optionallysubjected to steam stripping, as is well known.

The term “kerosene” as used herein refers to hydrocarbons boiling in therange of about 160-280, 160-270, 160-260, 170-280, 170-270, 170-260,180-280, 180-270, 180-260, 190-280, 190-270, 190-260, 193-280, 193-270or 193-260° C.

The term “light kerosene” as used herein refers to hydrocarbons boilingin the range of about 160-250, 160-235, 160-230, 160-225, 170-250,170-235, 170-230, 170-225, 180-250, 180-235, 180-230, 180-225, 190-250,190-235, 190-230 or 190-225° C.

The term “heavy kerosene” as used herein refers to hydrocarbons boilingin the range of about 225-280, 225-270, 225-260, 230-280, 230-270,230-260, 235-280, 235-270, 235-260 or 250-280° C.

The term “atmospheric gas oil” and its acronym “AGO” as used hereinrefer to hydrocarbons boiling in the range of about 250-400, 250-380,250-370, 250-360, 250-340, 250-320, 260-400, 260-380, 260-370, 260-360,260-340, 260-320, 270-400, 270-380, 270-370, 270-360, 270-340 or270-320° C.

The term “heavy atmospheric gas oil” and its acronym “H-AGO” as usedherein in certain embodiments refer to the heaviest cut of hydrocarbonsin the AGO boiling range including the upper 3-30° C. range (forexample, for AGO having a range of about 250-360° C., the range of H-AGOincludes an initial boiling point from about 330-357° C. and an endboiling point of about 360° C.). For example, H-AGO can includehydrocarbons boiling in the range of about 290-400, 290-380, 290-370,310-400, 310-380, 310-370, 330-400, 330-380, 330-370, 340-400, 340-380,340-370, 350-400, 350-380, 350-370, 360-370, 365-370, 290-360, 310-360,330-360, 340-360, 350-360, 355-360, 290-340, 310-340, 330-340, 335-340,290-320, 310-320 or 315-320° C.

The term “medium atmospheric gas oil” and its acronym “M-AGO” as usedherein in certain embodiments in conjunction with H-AGO to refer to theremaining AGO after H-AGO is removed, that is, hydrocarbons in the AGOboiling range excluding the upper about 3-30° C. range (for example, forAGO having a range of about 250-360° C., the range of M-AGO includes aninitial boiling point of about 250° C. and an end boiling point of fromabout 330-357° C.). For example, M-AGO can include hydrocarbons boilingin the range of about 250-365, 250-355, 250-335, 250-315, 260-365,260-355, 260-335, 260-315, 270-365, 270-355, 270-335 or 270-315° C.

In certain embodiments, the term “diesel” is used with reference to astraight run fraction from the atmospheric distillation unit, forinstance containing hydrocarbons boiling in the nominal range of about180-370° C. In embodiments in which this terminology is used herein, thediesel fraction also refers to medium AGO range hydrocarbons and incertain embodiments also in combination with heavy kerosene rangehydrocarbons.

The term “atmospheric residue” and its acronym “AR” as used herein referto the bottom hydrocarbons having an initial boiling point correspondingto the end point of the AGO range hydrocarbons, and having an end pointbased on the characteristics of the crude oil feed.

The term “vacuum gas oil” and its acronym “VGO” as used herein refer tohydrocarbons boiling in the range of about 370-550, 370-540, 370-530,370-510, 400-550, 400-540, 400-530, 400-510, 420-550, 420-540, 420-530or 420-510° C.

The term “light vacuum gas oil” and its acronym “LVGO” as used hereinrefer to hydrocarbons boiling in the range of about 370-425, 370-415,370-405, 370-395, 380-425, 390-425 or 400-425° C.

The term “heavy vacuum gas oil” and its acronym “HVGO” as used hereinrefer to hydrocarbons boiling in the range of about 425-550, 425-540,425-530, 425-510, 450-550, 450-540, 450-530 or 450-510° C.

The term “vacuum residue” and its acronym “VR” as used herein refer tothe bottom hydrocarbons having an initial boiling point corresponding tothe end point of the VGO range hydrocarbons, and having an end pointbased on the characteristics of the crude oil feed.

The term “fuels” refers to crude oil-derived products used as energycarriers. Fuels commonly produced by oil refineries include, but are notlimited to, gasoline, jet fuel, diesel fuel, fuel oil and petroleumcoke. Unlike petrochemicals, which are a collection of well-definedcompounds, fuels typically are complex mixtures of different hydrocarboncompounds.

The terms “kerosene fuel” or “kerosene fuel products” refer to fuelproducts used as energy carriers, such as jet fuel or other kerosenerange fuel products (and precursors for producing such jet fuel or otherkerosene range fuel products). Kerosene fuel includes but is not limitedto kerosene fuel products meeting Jet A or Jet A-1 jet fuelspecifications.

The terms “diesel fuel” and “diesel fuel products” refer to fuelproducts used as energy carriers suitable for compression-ignitionengines (and precursors for producing such fuel products). Diesel fuelincludes but is not limited to ultra-low sulfur diesel compliant withEuro V diesel standards.

The term “aromatic hydrocarbons” or “aromatics” is very well known inthe art. Accordingly, the term “aromatic hydrocarbon” relates tocyclically conjugated hydrocarbons with a stability (due todelocalization) that is significantly greater than that of ahypothetical localized structure (for example, Kekule structure). Themost common method for determining aromaticity of a given hydrocarbon isthe observation of diatropicity in its 1H NMR spectrum, for example thepresence of chemical shifts in the range of from 7.2 to 7.3 ppm forbenzene ring protons.

The term “wild naphtha” is used herein to refer to naphtha productsderived from hydroprocessing units such as distillate hydrotreatingunits, diesel hydrotreating units and/or gas oil hydroprocessing units.

The term “unconverted oil” and its acronym “UCO,” is used herein havingits known meaning, and refers to a highly paraffinic fraction from ahydrocracker with a low nitrogen, sulfur and Ni content and includinghydrocarbons having an initial boiling point corresponding to the endpoint of the AGO range hydrocarbons, in certain embodiments the initialboiling point in the range of about 340-370° C., for instance about 340,360 or 370° C., and an end point in the range of about 510-560° C., forinstance about 540, 550 or 560° C. UCO is also known in the industry byother synonyms including “hydrowax.”

The term “C # hydrocarbons” or “C #”, is used herein having itswell-known meaning, that is, wherein “#” is an integer value, and meanshydrocarbons having that value of carbon atoms.

The term “C #+ hydrocarbons” or “C #+” refers to hydrocarbons havingthat value or more carbon atoms. The term “C #− hydrocarbons” or “C #−”refers to hydrocarbons having that value or less carbon atoms.Similarly, ranges are also set forth, for instance, C1-C3 means amixture comprising C1, C2 and C3.

The term “petrochemicals” or “petrochemical products” refers to chemicalproducts derived from crude oil that are not used as fuels.Petrochemical products include olefins and aromatics that are used as abasic feedstock for producing chemicals and polymers. Typical olefinicpetrochemical products include, but are not limited to, ethylene,propylene, butadiene, butylene-1, isobutylene, isoprene, cyclopentadieneand styrene. Typical aromatic petrochemical products include, but arenot limited to, benzene, toluene, xylene, and ethyl benzene.

The term “olefin” is used herein having its well-known meaning, that is,unsaturated hydrocarbons containing at least one carbon-carbon doublebond. In plural, the term “olefins” means a mixture comprising two ormore unsaturated hydrocarbons containing at least one carbon-carbondouble bond. In certain embodiments, the term “olefins” relates to amixture comprising two or more of ethylene, propylene, butadiene,butylene-1, isobutylene, isoprene and cyclopentadiene.

The term “BTX” as used herein refers to the well-known acronym forbenzene, toluene and xylenes.

The term “make-up hydrogen” is used herein with reference tohydroprocessing zones to refer to hydrogen requirements of the zone thatexceed recycle from conventionally integrated separation vessels; incertain embodiments as used herein all or a portion of the make-uphydrogen in any given hydroprocessing zone or reactor within a zone isfrom gases derived from the steam cracking zone(s) in the integratedprocesses and systems.

The term “crude to chemicals conversion” as used herein refers toconversion of crude oil into petrochemicals including but not limited tolower olefins such as ethylene, propylene, butylenes (includingisobutylene), butadiene, MTBE, butanols, benzene, ethylbenzene, toluene,xylenes, and derivatives of the foregoing.

The term “crude to chemicals conversion ratio” as used herein refers tothe ratio, on a mass basis, of the influent crude oil before desalting,to petrochemicals.

The term “crude C4” refers to the mixed C4 effluent from a steamcracking zone.

The term “C4 Raffinate 1” or “C4 Raff-1” refers to the mixed C4s streamleaving the butadiene extraction unit, that is, mixed C4s from the crudeC4 except butadiene.

The term “C4 Raffinate 2” or “C4 Raff-2” refers to the mixed C4s streamleaving the MTBE unit, that is, mixed C4s from the crude C4 exceptbutadiene and isobutene.

The term “C4 Raffinate 3” or “C4 Raff-3” refers to the mixed C4s streamleaving the C4 distillation unit, that is, mixed C4s from the crude C4except butadiene, isobutene, and butane-1.

The terms “pyrolysis gasoline” and its abbreviated form “py-gas” areused herein having their well-known meaning, that is, thermal crackingproducts in the range of C5 to C9, for instance having an end boilingpoint of about 204.4° C. (400° F.), in certain embodiments up to about148.9° C. (300° F.).

The terms “pyrolysis oil” and its abbreviated form “py-oil” are usedherein having their well-known meaning, that is, a heavy oil fraction,C10+, that is derived from steam cracking.

The terms “light pyrolysis oil” and its acronym “LPO” as used herein incertain embodiments refer to pyrolysis oil having an end boiling pointof about 440, 450, 460 or 470° C.

The terms “heavy pyrolysis oil” and its acronym “HPO” as used herein incertain embodiments refer to pyrolysis oil having an initial boilingpoint of about 440, 450, 460 or 470° C.

The term “coker gas oil” is used herein to refer to hydrocarbons boilingabove an end point of the middle distillate range, for instance havingan initial boiling point in the range of about 320-370° C., and an endboiling point in the range of about 510-565° C., which are derived fromthermal cracking operations in a coker unit, for instance hydrocarbonsboiling in the range of about 320-565, 320-540, 320-510, 340-565,340-540, 340-510, 370-565, 370-540, or 370-510° C.

The term “light coker gas oil” is used herein to refer to coker gas oilin the light range, for instance having an end boiling point from about375-425° C., for instance hydrocarbons boiling in the range of about320-425, 320-400, 320-375, 340-425, 340-375, 340-375, 370-425, 370-400,or 370-375° C.

The term “heavy coker gas oil” is used herein to refer to coker gas oilin the heavy range, for instance having an initial boiling point fromabout 375-425° C., for instance hydrocarbons boiling in the range ofabout 375-565, 375-540, 375-510, 400-565, 400-540, 400-510, 425-565,425-540, or 425-510° C.

The term “coker naphtha” is used herein to refer to hydrocarbons boilingin the naphtha range derived from thermal cracking operations in a cokerunit.

The term “coker middle distillates” is used herein to refer tohydrocarbons boiling in the middle distillate range derived from thermalcracking operations in a coker unit.

In general, a suitable feedstock is processed in a coking zone unit toproduce at least light gases, coker naphtha, light coker gas oil andpetroleum coke. Light coker gas oil, and in certain embodimentshydrotreated light coker gas oil, is subjected to deep hydrogenation toproduce a deeply hydrogenated middle distillate fraction. All or aportion of the deeply hydrogenated middle distillate fraction is used asfeed to the stream cracking zone, to produce light olefins, pyrolysisgasoline and pyrolysis oil. The products from the steam cracking zoneH₂, methane, ethane, ethylene, mixed C3s and mixed C4s; pyrolysisgasoline stream(s); and pyrolysis oil stream(s). From the mixed productstream(s) C3s and the mixed C4s, petrochemicals ethylene, propylene andbutylenes are recovered. Ethane and non-olefinic C3s are recycled to thesteam cracking zone, and non-olefinic C4s are recycled to the steamcracking zone or to a separate processing zone for production ofadditional petrochemicals.

In certain embodiments, a coking zone is integrated in a refinery systemto produce petrochemicals and fuel products from a feedstock such ascrude oil feed. The system includes a separation zone such as anatmospheric distillation zone to separate at least a first atmosphericdistillation zone fraction comprising straight run naphtha and a secondatmospheric distillation zone fraction comprising at least a portion ofmiddle distillates. In certain embodiments, heavy middle distillatessuch as atmospheric gas oil or heavy atmospheric gas oil is subjected tocoking, a light coker gas oil product is hydrotreated, and thehydrotreated light coker gas oil is subjected to deep hydrogenation,thereby producing a hydrocarbon mixture effective as a feed for thermalcracking in a steam cracking complex to obtain light olefins. Lighteratmospheric distillation zone middle distillates (optionally subjectedto hydrotreating) can also be subjected to deep hydrogenation andincreasing the feed for thermal cracking in a steam cracking complex toobtain light olefins.

In certain embodiments, a third atmospheric distillation zone fractioncomprising atmospheric residue is also separated. In certainembodiments, a vacuum distillation zone is integrated to furtherseparate the third atmospheric distillation zone fraction into a firstvacuum distillation zone fraction comprising vacuum gas oil and a secondvacuum distillation zone fraction comprising vacuum residue. In theembodiments in which the second vacuum distillation zone fraction isrecovered, all or a portion of that fraction can optionally be processedin a vacuum residue treatment zone. A vacuum residue treatment zone caninclude one or more of residue hydroprocessing, delayed coking,gasification, or solvent deasphalting. In additional embodiments, all ora portion of the third atmospheric distillation zone fraction comprisingatmospheric residue is processed in an atmospheric residue treatmentzone, which can include one or more of residue hydroprocessing, fluidcatalytic cracking, delayed coking, gasification, or solventdeasphalting.

In a distillate hydrotreating (“DHT”) zone, such as a dieselhydrotreater, all or a portion of the second atmospheric distillationzone fraction is processed to produce at least a first DHT fraction anda second DHT fraction. The first DHT fraction comprises naphtha and thesecond DHT fraction is used as a hydrotreated middle distillate feed fordeep hydrogenation in the deep hydrogenation (“DHG”) zone.

In a gas oil hydroprocessing (“GOHP”) zone (which can be included fortreatment of gas oil range streams, for instance atmospheric gas oil orvacuum gas oil if a vacuum distillation zone is used, or other gas oilrange components obtained from other treatment of residue), all or aportion of gas oil components within the integrated process aresubjected to hydrotreating, or hydrotreating and hydrocracking. The GOHPzone generally produces at least a first GOHP fraction and a second GOHPfraction. The first GOHP fraction comprises naphtha and the second GOHPfraction comprise middle distillates, and is used as a source ofhydrotreated middle distillate feed for the DHG zone. The second GOHPfraction can be routed to the DHG zone directly, and/or subjected tofurther treatment to remove sulfur, nitrogen and/or other heteroatoms,for example by routing to the DHT zone. In addition, the GOHP zoneproduces hydrotreated gas oil and/or unconverted oil (depending on themode of operation). In certain embodiments, the hydrotreated gas oiland/or unconverted oil is subjected to coking, a light coker gas oilproduct is hydrotreated, and the hydrotreated light coker gas oil issubjected to deep hydrogenation, thereby producing a hydrocarbon mixtureeffective as a feed for thermal cracking in a steam cracking complex toobtain light olefins.

In certain embodiments, a vacuum residue treatment zone and/or anatmospheric residue treatment zone can include a residue hydroprocessingzone such as a residue hydrocracker. In certain embodiments a residuehydroprocessing zone includes a preceding residue hydrotreating step,and/or a post hydrotreating step. The residue hydroprocessing zonegenerally produces distillates naphtha, middle distillates, unconvertedoil and pitch. The residue hydroprocessing zone products can be used asconventionally known. In certain embodiments of the processes herein,all or a portion of the middle distillates range products from thevacuum residue hydroprocessing zone and/or the atmospheric residuetreatment zone can be passed to the GOHP zone (if included), the DHTzone or directly used as middle distillate feed for the DHG zone.

In certain embodiments, a vacuum residue treatment zone and/or anatmospheric residue treatment zone can include a coking zone such asdelayed coking to process all or a portion of vacuum residue (straightrun vacuum residue or vacuum residue that has been subjected totreatment to remove sulfur, nitrogen and/or other heteroatoms), or allor a portion of atmospheric residue (straight run atmospheric residue oratmospheric residue that has been subjected to treatment to removesulfur, nitrogen and/or other heteroatoms). The coking liquid and gasproducts can be used as conventionally known. In certain embodiments ofthe processes herein, all or a portion of the middle distillates fromthe coking liquid and gas products, including light coker gasoil fromthe coking zone products is used as additional middle distillate feedfor deep hydrogenation. If necessary, all or a portion of the middledistillate range coker liquid products can be subjected to treatment toremove sulfur, nitrogen and/or other heteroatoms prior to deephydrogenation; the additional treatment of middle distillate range cokerliquid products can comprise a dedicated treatment unit or step, or oneor more of the units or steps within the integrated process and systemsuch as the GOHP zone (if included) or the DHT zone. In embodiments inwhich middle distillate range coker liquid products are passed to theGOHP zone (if included) or the DHT zone, severity of the conditions inthose zones may be increased to accommodate the higher concentrations ofsulfur, nitrogen and/or other heteroatoms.

In certain embodiments, a vacuum residue treatment zone and/or anatmospheric residue treatment zone can include a solvent deasphaltingzone to process all or a portion of vacuum residue (straight run vacuumresidue or vacuum residue that has been subjected to treatment to removesulfur, nitrogen and/or other heteroatoms), or all or a portion ofatmospheric residue (straight run atmospheric residue or atmosphericresidue that has been subjected to treatment to remove sulfur, nitrogenand/or other heteroatoms). The deasphalted oil phase and the asphaltphase can be used as conventionally known. In certain embodiments of theprocesses herein, all or a portion of the deasphalted oil is used as asource of additional middle distillate feed for the DHG zone. Forexample, all or a portion of the deasphalted oil can be subjected totreatment to remove sulfur, nitrogen and/or other heteroatoms prior todeep hydrogenation; the additional treatment of deasphalted oil cancomprise a dedicated treatment unit or step, or one or more of the unitsor steps within the integrated process and system such as a vacuumresidue treatment zone (if included), the GOHP zone (if included) or theDHT zone. In embodiments in which deasphalted oil is passed to the DHTzone, severity of the conditions in those zones may be increased toaccommodate the higher concentrations of sulfur, nitrogen and/or otherheteroatoms.

In certain embodiments, a vacuum residue treatment zone and/or anatmospheric residue treatment zone can include a gasification zone toprocess all or a portion of vacuum residue (straight run vacuum residueor vacuum residue that has been subjected to treatment to remove sulfur,nitrogen and/or other heteroatoms), or all or a portion of atmosphericresidue (straight run atmospheric residue or atmospheric residue thathas been subjected to treatment to remove sulfur, nitrogen and/or otherheteroatoms). The produced syngas can be used as conventionally known.In certain embodiments of the processes herein, syngas is subjected towater-gas shift reaction as is conventionally known to produce hydrogenthat can be recycled to hydrogen users in the system, such as a residuehydroprocessing unit (if included), the GOHP zone (if included) or theDHT zone.

In certain embodiments, an atmospheric residue treatment zone comprisesa delayed coking zone. The feed can be straight run atmospheric residueor atmospheric residue that has been subjected to treatment to removesulfur, nitrogen and/or other heteroatoms. The delayed coking productscan be used as conventionally known. In certain embodiments of theprocesses herein, all or a portion of light coker gas oil from thedelayed coking products is used as additional middle distillate feed forthe DHG zone. If necessary, all or a portion of the light coker gas oilcan be subjected to treatment to remove sulfur, nitrogen and/or otherheteroatoms prior to deep hydrogenation; the additional treatment oflight coker gas oil can comprise a dedicated treatment unit or step, orone or more of the units or steps within the integrated process andsystem such as the gas oil hydroprocessing zone or the DHT zone. Inembodiments in which light coker gas oil is passed to the gas oilhydroprocessing zone or the DHT zone, severity of the conditions inthose zones may be increased to accommodate the higher concentrations ofsulfur, nitrogen and/or other heteroatoms.

All or a portion of the hydrotreated middle distillates from the DHTzone are passed to the DHG zone to produce hydrogenated middledistillates. In certain embodiments, middle distillates from the GOHPzone (if included) are subjected to deep hydrogenation, in the same DHGzone as the hydrotreated middle distillates from the DHT zone, or in aseparate DHG zone. In certain embodiments, middle distillates obtainedfrom the VR and/or AR treatment zones (if included), if necessarysuitably pretreated in separate treatment units or integrated units suchas the DHT zone or the GOHP zone (if included), are subjected to deephydrogenation, in the same DHG zone as the hydrotreated middledistillates from the DHT zone, in the same DHG zone as the middledistillates from the GOHP zone (if included), or in a separate DHG zone.

In the process herein, all or a portion of the hydrogenated middledistillates produced in the DHG zone(s) are processed in a steamcracking zone. The products from the steam cracking zone include mixedproduct stream(s) comprising H₂, methane, ethane, ethylene, mixed C3sand mixed C4s; pyrolysis gasoline stream(s); and pyrolysis oilstream(s). From the mixed product stream C3s and the mixed C4s,petrochemicals ethylene, propylene and butylenes are recovered. Ethaneand non-olefinic C3s are recycled to the steam cracking zone, andnon-olefinic C4s are recycled to the steam cracking zone or to aseparate processing zone for production of additional petrochemicals.Ethane and non-olefinic C3s and C4s are recovered, with ethane andnon-olefinic C3s recycled to the steam cracking complex, andnon-olefinic C4s recycled to the steam cracking complex or passed to aseparate processing zone for production of additional petrochemicalssuch as propylene and/or mixed butanol liquids.

FIG. 1 schematically depicts an embodiment of a process and system 1100for conversion of crude oil to petrochemicals and fuel products, thatis, without deep hydrogenation of middle distillates as additional steamcracking feedstock. This embodiment is depicted for illustrativepurpose, and the various unit operations and various streams are denotedas a “1000” series of reference numerals. In further embodimentsdescribed herein, deep hydrogenation of middle distillates is integratedto produce additional steam cracking feedstock rather than fuel productssuch as kerosene and/or diesel fuel products or blending components.

The system 1100 generally includes a crude complex 1105, typicallyincluding an atmospheric distillation zone (“ADU”) 1110, a saturated gasplant 1130, a vacuum distillation zone (“VDU”) 1140 and a coking zone1300. A steam cracking complex 1215 is integrated and typically receivesplural naphtha streams, shown as a combined naphtha stream 1222including straight run naphtha and other naphtha fractions producedwithin the system; an optional kerosene sweetening zone 1120 producingkerosene fuel fraction 1118 as a fuel product and/or blending component;a diesel hydrotreating zone 1150 producing a hydrotreated naphthafraction 1152 (sometimes referred to as wild naphtha) as part of thecombined naphtha stream 1222, and a diesel fuel fraction 1154 as a fuelproduct and/or blending component; a gas oil hydroprocessing zone1160/1170 operating as a gas oil hydrocracking zone 1160 or as a gas oilhydrotreating zone 1170, and in certain embodiments operating underconditions used in vacuum gas oil hydrotreating and/or hydrocracking. Ahydrocracking zone 1160 produces a naphtha fraction 1162 as part of thecombined naphtha stream 1222, a diesel fuel fraction 1164 as a fuelproduct and/or blending component, and an unconverted oil fraction 1166.A hydrotreating zone 1170 produces a hydrotreated naphtha fraction 1172and a hydrotreated gas oil fraction 1176.

A vacuum residue conditioning zone 1180 can be integrated, for instance,a vacuum residue hydrocracking zone producing a naphtha stream 1184 aspart of the combined naphtha stream 1222, a diesel fraction 1186, anunconverted oil fraction 1188 and pitch 1190. In certain embodiments amiddle distillates stream 1182 (instead of the diesel fraction or inconjunction therewith) is routed to the gas oil hydroprocessing zone1160/1170 and/or the diesel hydrotreating zone 1150.

A feed 1102 is separated into fractions in a crude complex 1105,typically including an atmospheric distillation zone (“ADU”) 1110, asaturated gas plant 1130 and a vacuum distillation zone (“VDU”) 1140.The feed 1102 can be crude oil, or in certain embodiment the feed can becrude oil that has been subjected to hydrotreating (hydrotreated crudeoil), solvent deasphalting (deasphalted oil) or coking, such as delayedcoking (coker liquid and gas products). The atmospheric distillationunit and vacuum distillation unit are used in well-known arrangements.The feed 1102, in certain embodiments having LPG and light naphtharemoved, is separated into fractions in the atmospheric distillationzone 1110. In embodiments in which LPG and light naphtha are removed,those products can be sent to the same steam cracking complex 1215, aseparate steam cracking complex, or used for other purposes. Lightproducts, for instance, light hydrocarbons with fewer than six carbons,are passed to the steam cracking zone 1220. In particular, C2-C4hydrocarbons 1136 including ethane, propane and butanes are separatedfrom the light ends and LPG 1112 from the atmospheric distillation zone1110 via the saturated gas plant 1130. Optionally, other light productsare routed to the saturated gas plant 1130, shown in dashed lines asstream 1134, such as light gases from refinery units within theintegrated system, and in certain embodiments light gases from outsideof the battery limits. The separated C2-C4 hydrocarbons 1136 are routedto the steam cracking complex 1215. Sweet off-gases 1132 from thesaturated gas plant 1130 and off-gases 1234 from the steam crackingcomplex 1215 (via an olefins recovery train 1230) are removed andrecovered as is typically known, for instance to contribute to a fuelgas (“FG”) system, or in certain embodiments recycled to the steamcracker. Off-gases from the coking unit, after passing through anunsaturated gas plant, can be integrated with off-gases from thesaturated gas plant 1130 for common handling of the fuel gases.

Straight run naphtha 1114 from the atmospheric distillation zone 1110 ispassed to the stream cracking zone 1220. In certain embodiments, all, asubstantial portion or a significant portion of the straight run naphtha1114 is routed to the stream cracking zone 1220. Remaining naphtha (ifany) can be upgraded if necessary and added to a gasoline pool. Inaddition, the straight run naphtha stream 1114 can contain naphtha fromother sources as described herein and sometimes referred to as wildnaphtha, for instance, naphtha range hydrocarbons from one or more ofthe integrated distillate, gas oil and/or residue hydroprocessing units.In additional embodiments, one or more straight run naphtha stream(s)are recovered from the atmospheric distillation zone 1110, for instancea light naphtha stream and a heavy naphtha stream. In such embodiments,all or a portion of straight run light naphtha can be routed to thesteam cracker, while all or a portion of heavy naphtha is subjected tohydroprocessing (hydrotreating and/or hydrogenation). In certainembodiments, all, a substantial portion or a significant portion ofstraight run light naphtha is routed to the stream cracking zone 1220,while all, a substantial portion or a significant portion of heavynaphtha is routed to hydrotreating and/or hydrogenation process units.

Middle distillates are used to produce diesel and/or kerosene, andadditional naphtha feed to the steam cracking complex 1215. In theembodiment shown in FIG. 1, at least three different middle distillatecuts are processed for production of fuel products and petrochemicals(via the steam cracker). In one example using the arrangement shown inFIG. 1, a first atmospheric distillation zone middle distillate fraction1116, in certain embodiments referred to as a kerosene fraction,contains light kerosene range hydrocarbons, a second atmosphericdistillation zone middle distillate fraction 1122, in certainembodiments referred to as a diesel fraction, contains heavy kerosenerange hydrocarbons and medium AGO range hydrocarbons, and a thirdatmospheric distillation zone middle distillate fraction 1124, incertain embodiments referred to as an atmospheric gas oil fraction,contains heavy AGO range hydrocarbons. In another example using thearrangement shown in FIG. 1, a first middle distillate fraction 1116contains kerosene range hydrocarbons, a second middle distillatefraction 1122 contains medium AGO range hydrocarbons and a third middledistillate fraction 1124 contains heavy AGO range hydrocarbons. Inanother example using the arrangement shown in FIG. 1, a first middledistillate fraction 1116 contains light kerosene range hydrocarbons anda portion of heavy kerosene range hydrocarbons, a second middledistillate fraction 1122 contains a portion of heavy kerosene rangehydrocarbons and a portion of medium AGO range hydrocarbons and a thirdmiddle distillate fraction 1124 contains a portion of medium AGO rangehydrocarbons and heavy AGO range hydrocarbons.

For example, a first middle distillate fraction 1116 can be processed ina kerosene sweetening process 1120 to produce kerosene fuel product1118, for instance, jet fuel compliant with Jet A or Jet A-1specifications, and optionally other fuel products (not shown). Incertain embodiments herein, all or a portion of the first middledistillate fraction 1116 is not used for fuel production, but rather isused as a feed for distillate hydrotreating so as to produce additionalfeed for the stream cracking zone 1220 by production of additional wildnaphtha.

A second middle distillate fraction 1122 is processed in a distillatehydrotreating zone such as a diesel hydrotreating zone 1150, to producewild naphtha 1152 and a diesel fuel fraction 1154, for instance, as adiesel fuel blending component that can be compliant with Euro V dieselstandards. In additional embodiments, all or a portion of the firstmiddle distillate fraction 1116 can be treated with the second middledistillate fraction 1122, as denoted by a dashed line. In furtherembodiments, the diesel hydrotreating zone 1150 can also processdistillate products from the gas oil hydroprocessing zone. All or aportion of the wild naphtha 1152 is routed to the steam cracking zone1220; any portion that is not passed to the steam cracking zone 1220 canbe upgraded if necessary and routed to the gasoline pool. In certainembodiments, the wild naphtha 1152 is routed through the crude complex1105, alone, or in combination with other wild naphtha fractions fromwithin the integrated process. In embodiments in which the wild naphtha1152 is routed through the crude complex 1105, all or a portion of theLPG produced in the diesel hydrotreating zone 1150 can be passed withthe wild naphtha fraction 1152. In certain embodiments, all, asubstantial portion, a significant portion or a major portion of thewild naphtha 1152 is routed to the steam cracking zone 1220 (directly orthrough the crude complex 1105).

In certain embodiments (as denoted by dashed lines), all, a substantialportion, a significant portion or a major portion of the third middledistillate fraction 1124 is routed to the gas oil hydroprocessing zone1160/1170 in combination with the vacuum gas oil stream 1144. Inadditional embodiments in which vacuum distillation is not used, thethird middle distillate fraction 1124 is routed to the gas oilhydroprocessing zone 1160/1170 and/or a residue treatment zone.

In certain embodiments, the first middle distillate fraction 1116 can berouted either through the kerosene sweetening zone 1120 or routed to thedistillate hydrotreating zone 1150. During periods in which maximizingthe fuel fraction 1118 is desired, the first middle distillate fraction1116 can be routed to the kerosene sweetening zone 1120. During periodsin which the naphtha range feedstock to the steam cracking zone 1220 isto be maximized, the first middle distillate fraction 1116 can be routedto the distillate hydrotreating zone 1150, so as to produce additionalhydrotreated naphtha 1152. In additional alternative embodiments, thefirst middle distillate fraction 1116 can be divided (on a volume orweight basis, for example, with a diverter) so that a portion is passedto the distillate hydrotreating zone 1150 and the remaining portion ispassed to the kerosene sweetening zone 1120.

In certain embodiments, the first middle distillate fraction 1116 can berouted either through the kerosene sweetening zone 1120 or routed to thedistillate hydrotreating zone 1150. During periods in which maximizingthe fuel fraction 1118 is desired, the first middle distillate fraction1116 can be routed to the kerosene sweetening zone 1120. During periodsin which the naphtha range feedstock to the steam cracking zone 1220 isto be maximized, the first middle distillate fraction 1116 can be routedto the distillate hydrotreating zone 1150, so as to produce additionalhydrotreated naphtha 1152. In additional alternative embodiments, thefirst middle distillate fraction 1116 can be divided (on a volume orweight basis, for example, with a diverter) so that a portion is passedto the distillate hydrotreating zone 1150 and the remaining portion ispassed to the kerosene sweetening zone 1120.

In other embodiments, kerosene sweetening can be eliminated.Accordingly, a relatively light middle distillate fraction includingseparate or combined streams corresponding to streams 1116 and 1122 arerouted to the distillate hydrotreating zone 1150, and a heavier middledistillate fraction 1124 is treated as described above. In one example arelatively light middle distillate fraction 1116 and 1122 containskerosene range hydrocarbons and medium AGO range hydrocarbons, and aheavier atmospheric distillation zone middle distillate fraction 1124contains heavy AGO range hydrocarbons. In another example the relativelylight middle distillate fraction 1116 and 1122 contains kerosene rangehydrocarbons and a portion of medium AGO range hydrocarbons and theheavier middle distillate fraction 1124 contains a portion of medium AGOrange hydrocarbons and heavy AGO range hydrocarbons.

In certain embodiments an atmospheric residue fraction 1126 from theatmospheric distillation zone 1110 is further separated in the vacuumdistillation zone 1140, generally into vacuum gas oil fraction 1144 anda vacuum residue fraction 1142. Vacuum gas oil 1144 from the vacuumdistillation zone 1140 is routed to the gas oil hydroprocessing zone1160/1170. In certain embodiments, a minor portion of the atmosphericresidue fraction 1126 can bypass the vacuum distillation zone 1140 (notshown) and is routed to the vacuum residue conditioning zone 1180 withthe vacuum residue fraction 1142. In certain embodiments, 0-100% of theatmospheric residue fraction 1126 can bypass the vacuum distillationzone 1140 (not shown) and is routed to the vacuum residue conditioningzone 1180. For instance, in certain embodiments vacuum distillation isbypassed or not used, and atmospheric residue 1126 is the feed to thevacuum residue conditioning zone 1180. In certain embodiments, a minorportion of the atmospheric residue fraction 1126, shown as portion 1302,can bypass the vacuum distillation zone 1140 and is routed to the cokingzone 1300. In certain embodiments, 0-100% of the atmospheric residuefraction 1126 can be used as portion 1302 to the coking zone 1300.

In certain embodiments, all, a substantial portion, a significantportion or a major portion of the vacuum gas oil 1144 is routed to thegas oil hydroprocessing zone 1160/1170. In addition, the gas oilfractions from the vacuum distillation zone 1140 can include one or moreVGO fractions, such as a light vacuum gas oil stream and a heavy vacuumgas oil stream. In certain optional embodiments, in addition to vacuumgas oil and optionally atmospheric gas oil, the gas oil hydroprocessingzone 1160/1170 can also process atmospheric and/or vacuum gas oil rangeproducts from the vacuum residue conditioning zone 1180. In certainembodiments vacuum gas oil hydroprocessing is with a gas oilhydrocracking zone 1160 that can operate under mild, moderate or severehydrocracking conditions, and generally produces a hydrocracked naphthafraction 1162, a diesel fuel fraction 1164, and an unconverted oilfraction 1166. The diesel fuel fraction 1164 is recovered as fuel, forinstance, as a diesel fuel blending component that can be compliant withEuro V diesel standards, and can be combined with the diesel fuelfraction 1154 from the diesel hydrotreating zone 1150. In otherembodiments, vacuum gas oil hydroprocessing is with a gas oilhydrotreating zone 1170 that can operate under mild, moderate or severehydrotreating conditions, and generally produces a hydrotreated gas oilfraction 1176, naphtha and some middle distillates. Naphtha rangeproducts can be separated from products within the gas oil hydrotreatingzone 1170 as a hydrotreated naphtha stream 1172. Alternatively, or inconjunction with the hydrotreated naphtha stream 1172, a crackeddistillates stream 1174 containing hydrotreated distillates (and incertain embodiments naphtha range products) are routed to dieselhydrotreating zone 1150 for further hydroprocessing and/or separationinto diesel hydrotreating zone 1150 products.

In certain embodiments, all, a substantial portion, a significantportion or a major portion of the wild naphtha fraction from the gas oilhydroprocessing zone 1160/1170, streams 1162 or 1172, is routed to thesteam cracking zone 1220, alone, or in combination with other wildnaphtha fractions from within the integrated process; any portion thatis not passed to the steam cracking zone 1220 can be upgraded ifnecessary and routed to the gasoline pool. In certain embodiments, thewild naphtha fraction from the gas oil hydroprocessing zone 1160/1170 isrouted through the crude complex 1105, alone, or in combination withother wild naphtha fractions from within the integrated process. Inembodiments in which the wild naphtha fraction from the gas oilhydroprocessing zone 1160/1170 is routed through the crude complex 1105,all or a portion of the LPG produced in the gas oil hydroprocessing zone1160/1170 can be passed with the wild naphtha. In certain embodiments,all or any portion of the heavy product from the gas oil hydroprocessingzone 1160/1170 is routed to the vacuum residue conditioning zone 1180.Alternatively, any remainder can be recycled and further processed(cracked to extinction in VGO hydrocracking) and/or bled from thesystem.

A vacuum residue fraction 1142 from the vacuum distillation zone 1140can be recovered as a fuel oil pool component. Optionally, a vacuumresidue conditioning zone 1180 can be used to treat the vacuum residuefraction 1142; in such embodiments, all, a substantial portion, asignificant portion, a major portion or a minor portion of the vacuumresidue fraction 1142 is passed to the vacuum residue conditioning zone1180, and remaining vacuum residue (if any) can be recovered as a fueloil pool component.

The vacuum residue conditioning zone 1180 can be a residue crackeroperating under hydrocracking conditions, in certain embodiments severehydrocracking conditions, effective to produce off-gas and light ends(not shown), a hydrocracked gas oil fraction 1188, pitch 1190, and oneor more distillate streams (including one or more of a wild naphthastream 1184, a diesel fraction 1186. The diesel fraction 1186 isrecovered as a diesel fuel pool component, or used as diesel fuelcompliant with Euro V standards. In certain embodiments a middledistillates stream 1182 (instead of the diesel fraction or inconjunction therewith) is routed to the gas oil hydroprocessing zone1160/1170 and/or the diesel hydrotreating zone 1150. In embodiments inwhich the vacuum residue hydrocracking zone 1180 operates underconditions effective to produce a diesel fuel blending component, forinstance diesel fuel compliant with Euro V standards, the fraction 1186can be combined with the diesel fuel fraction 1154 from the dieselhydrotreater 1150 or diesel fuel fraction 1164 from the gas oilhydrocracking zone 1160, or both the diesel fuel fraction 1154 from thediesel hydrotreater 1150 and the diesel fuel fraction 1164 from the gasoil hydrocracking zone 1160.

In embodiments in which a separate wild naphtha stream 1184 isrecovered, all, a substantial portion, a significant portion or a majorportion of the wild naphtha stream 1184 is routed to the steam crackingzone 1220, alone, or in combination with other wild naphtha fractionsfrom within the integrated process; any portion that is not passed tothe steam cracking zone 1220 can be upgraded if necessary and routed tothe gasoline pool. In certain embodiments, the wild naphtha stream 1184is routed through the crude complex 1105, alone, or in combination withother wild naphtha fractions from within the integrated process. Inembodiments in which the wild naphtha stream 1184 is routed through thecrude complex 1105, all or a portion of the LPG produced in the gas oilhydroprocessing zone 1160/1170 can be passed with the wild naphtha.

In certain optional embodiments, all or portion of the hydrocracked gasoil fraction 1188 is routed to the gas oil hydroprocessing zone1160/1170. For instance, all, a substantial portion, a significantportion or a major portion of the hydrocracked gas oil fraction 1188from the vacuum residue hydrocracking zone 1180 is routed to the gas oilhydroprocessing zone 1160/1170. The remainder (if any) can be processedin other units and/or bled from the system.

The coking zone 1300 is typically operable to produce at least lightgases 1330, coker naphtha 1332, light coker gas oil 1334, heavy cokergas oil 1336, and coke 1338. Off-gases from the coking zone 1300 can beintegrated with the fuel gas system. In certain embodiments (not shown),certain gases, after treatment in an unsaturated gas plant, can berouted to the separation units within the steam cracking complex 1215,and/or LPGs can be routed to the steam cracking zone 1220. All, asubstantial portion, a significant portion or a major portion of thegases containing light olefins (a C2− stream and a C3+ stream) arerouted through the unsaturated gas plant. The remainder, if any, can berouted to the steam cracking zone 1220 and/or the olefins recovery train1230.

In certain embodiments, all or a portion of the coker naphtha 1332 canbe processed as described below in a py-gas hydrotreatment and recoverycenter 1270/1272, to increase the quantity of raffinate as additionalfeed to the steam cracking zone 1220. Any portion of the coker naphtha1332 that is not routed to the py-gas hydrotreatment and recovery center1270/1272, shown in dashed lines, can be hydrotreated and recovered forfuel production. For instance, in modalities in which the objective ismaximum petrochemical production, all, a substantial portion, asignificant portion or a major portion of the coker naphtha 1332 isrouted to the py-gas hydrotreatment and recovery center 1270/1272; theremainder, if any, is recovered for fuel production and incorporationinto a gasoline pool.

In additional embodiments, all or a portion of the coker naphtha 1332 ishydrotreated and recovered for fuel production and incorporation into agasoline pool. Optionally, a portion of the coker naphtha 1332 that isnot recovered for fuel production can be processed in the py-gashydrotreatment and recovery center 1270/1272, as shown in dashed lines,to increase the quantity of raffinate as additional feed to the steamcracking zone 1220.

Other products from the coking zone 1300 include cycle oil, such aslight coker gas oil 1334 and heavy coker gas oil 1336. All or a portionof the light coker gas oil 1334 can be routed to the dieselhydrotreating zone 1150, increasing the yield of the diesel fuelfraction 1154 and wild naphtha 1152 that can be passed to the steamcracking zone 1220. In certain embodiments, all, a substantial portion,a significant portion or a major portion of the light coker gas oil 1334is passed to the diesel hydrotreating zone 1150, and any remainingportion can be routed to the vacuum residue conditioning zone. Heavycoker gas oil stream 1336 can be routed to a fuel oil pool and/or usedas feedstock for production of carbon black.

Embodiments are disclosed herein for separation of products from aquenched cracked gas stream containing mixed C1-C4 paraffins andolefins, and for treatment and handling of pyrolysis gasoline andpyrolysis fuel oil stream 1226. However, it should be appreciated thatother operations can be used to separate petrochemical products from thesteam cracker effluents. In certain embodiments as disclosed in FIG. 1,the steam cracking zone 1220 operates in conjunction with the olefinsrecovery train 1230 to convert the feeds into a mixed products stream1224 that is separated into products ethylene 1236, a mixed C3s stream1238 used to produce propylene 1248, and mixed C4s stream 1240 used toproduce C4 olefin products (for instance 1,3-butadiene product stream1252 and 1-butene product stream 1268), and hydrogen 1232 and off-gases1234, typically from the olefins recovery train 1230. Pyrolysis gasoline1228 and pyrolysis oil 1226 are also recovered. The off-gases 1234 canbe passed to an integrated fuel gas system. Further, the hydrogen 1232that is recovered from the cracked products can be recycled to hydrogenusers within the complex limits. In certain embodiments hydrogen for allhydrogen users in the integrated process and system is derived fromhydrogen 1232 recovered from the cracked products, and no outsidehydrogen is required once the process has completed start-up and reachedequilibrium. In further embodiments excess hydrogen can be recovered.While particular arrangements of unit operations are shown to recoverthe main light olefin products and recycle streams, a person havingordinary skill in the art will appreciate that other arrangements can beused.

In a typical arrangement, the mixed C4s stream 1240 containing a mixtureof C4s from the olefins recovery train 1230 of the steam cracker complex1215, known as crude C4s, is routed to a butadiene extraction unit 1250to recover a high purity 1,3-butadiene product 1252. A first raffinate1254 (“C4-Raff-1”) containing butanes and butenes is passed to aselective hydrogenation unit (“SHU”) and methyl tertiary butyl ether(“MTBE”) unit, SHU and MTBE zone 1256, where it is mixed with highpurity fresh methanol 1258 from outside battery limits to produce methyltertiary butyl ether 1262.

A second raffinate 1260 (“C4 Raff-2”) from the SHU and MTBE zone 1256 isrouted to a C4 distillation unit 1266 for separation into a 1-buteneproduct stream 1268 and an alkane stream 1264 (a third raffinate “C4Raff-3”) containing residual C4s, which is recycled to the steamcracking zone 1220. Separation of the ethylene 1236, propylene 1248 andthe mixed C4s stream 1240 occurs in a suitable arrangement of knownseparation steps for separating steam cracking zone effluents, includingcompression stage(s), depropanizer, debutanizer, demethanizer anddeethanizer.

In further embodiments of processes and systems for conversion of crudeoil to petrochemicals and fuel products, metathesis conversion of C4 andC5 olefins is included to produce additional propylene. The processoperates as described in conjunction with FIG. 1 upstream of the steamcracking operations and with respect to the coking operations.Downstream of the steam cracking operations, the butadiene extractiontrain can operate in a manner similar to that above, with a mixed C4raffinate stream (“C4 Raff 3”) from the C4 distillation unit routed to ametathesis unit for metathesis conversion to additional propylene.

In further embodiments of processes and systems for conversion of crudeoil to petrochemicals and fuel products, an additional step is providedto convert a mixture of butenes into mixed butanols suitable as agasoline blending oxygenate and for octane enhancement. Suitableprocesses to convert a mixture of butenes into mixed butanols aredescribed in one or more of commonly owned US Patent PublicationUS20150148572A1, and commonly owned US Patents U.S. Ser. No.10/155,707B2, U.S. Pat. No. 9,732,018B2, U.S. Pat. No. 9,447,346B2, U.S.Pat. No. 9,393,540B2, U.S. Pat. No. 9,187,388B2, U.S. Pat. No.8,999,013B2, U.S. Pat. No. 8,629,080B2 and U.S. Pat. No. 8,558,036B2,all of which are incorporated by reference herein in their entireties.In certain embodiments, a particularly effective conversion processknown as “SuperButol™” technology is integrated, which is a one-stepprocess that converts a mixture of butenes into mixed butanol liquids.Downstream of the steam cracking operations, the butadiene extractiontrain can operate in a manner similar to that above, with a mixed C4raffinate stream (“C4 Raff 3”) from the C4 distillation unit that isrouted to a mixed butanols production zone to convert the mixture ofbutenes into mixed butanol liquids, and alkanes are recycled to thesteam cracking zone.

The crude complex 1105 is schematically depicted. Components of thecrude complex not shown but which are well-known can includefeed/product and pump-around heat exchangers, crude charge heaters,crude tower(s), product strippers, cooling systems, hot and coldoverhead drum systems including re-contactors and off-gas compressors,and units for water washing of overhead condensing systems. Theatmospheric distillation zone 1110 can include well-known designfeatures. In certain embodiments, all or portions of the naphtha andmiddle distillate (for instance kerosene and atmospheric gas oilproducts) from the atmospheric distillation column 1110 aresteam-stripped in side strippers, and atmospheric residue can besteam-stripped in a reduced-size can section inside the bottom of theatmospheric distillation column. The vacuum distillation zone 1140, caninclude well-known design features, such as operation at reducedpressure levels (mm Hg absolute pressure), for instance, in the range ofabout 10-40, which can be maintained by steam ejectors or mechanicalvacuum pumps.

The total feed to the atmospheric distillation zone 1110 is primarilythe feed 1102, although it shall be appreciated that wild naphtha, LPGsand off-gas streams from the diesel hydrotreating zone 1150 and incertain embodiments from the gas oil hydroprocessing step and/or thevacuum residue hydrocracking zone 1180 can be routed to the atmosphericdistillation zone 1110 where they are fractionated before being passedto the steam cracking complex. A desalting unit (not shown) is typicallyincluded upstream of the distillation zone 1110. A substantial amount ofthe water required for desalting can be obtained from a sour waterstripper within the integrated process and system.

The saturated gas plant 1130 generally comprises a series of operationsincluding fractionation and in certain systems absorption andfractionation, as is well known, with an objective to process light endsto separate fuel gas range components from LPG range components suitableas a steam cracker feedstock. The light ends that are processed in oneor more saturated gas plants within embodiments of the integrated systemand process herein are derived from the crude distillation, such aslight ends and LPG. In addition, other light products can optionally berouted to the saturated gas plant 1130, shown in dashed lines as stream1134, such as light gases from refinery units within the integratedsystem, and in certain embodiments light gases from outside of thebattery limits. For instance, stream 1134 can contain off-gases andlight ends from the diesel hydrotreating zone 1150, the gas oilhydroprocessing zone, and/or the vacuum residue hydrocracking zone 1180.The products from the saturated gas plant 1130 include: an off-gasstream 1132 containing C1-C2 alkanes that is passed to the fuel gassystem and/or the cracker complex; and a light ends stream 1136,containing C2+, that is passed to the steam cracking unit 1220.

In certain embodiments, a suitable saturated gas plant 1130 includesamine and caustic washing of liquid feed, and amine treatment of vaporfeed, before subsequent steps. The crude tower overhead vapor iscompressed and recontacted with naphtha before entering an aminescrubber for H₂S removal and is then routed to the steam crackercomplex. Recontact naphtha is debutanized to remove LPGs which are aminewashed and routed to the steam cracker complex.

The debutanized naphtha is routed separately from the heavy naphtha tothe steam cracker complex. As is known, light naphtha absorbs C4 andheavier hydrocarbons from the vapor as it travels upward through anabsorber/debutanizer. Off-gasses from the absorber/debutanizer iscompressed and sent to a refinery fuel gas system. A debutanizer bottomsstream is sent to the steam cracker as an additional source of feed.

As shown, the first middle distillate fraction 1116 is processed in akerosene sweetening zone 1120 to remove unwanted sulfur compounds, as iswell-known. Treated kerosene is recovered as a kerosene fuel product1118, for instance, jet fuel compliant with Jet A or Jet A-1specifications, and optionally other fuel products. In certainembodiments, all or a portion of the first middle distillate fraction1116 is not used for fuel production, but rather is used as a feed fordistillate hydrotreating so as to produce additional feed for the streamcracking zone 1220. For instance, a kerosene sweetening zone 1120operates as is well-established commercially, and appropriate operatingconditions are well known to produce kerosene fuel product 1118 anddisulfide oils as by-products. In certain kerosene sweetening processes,impregnated carbon is utilized as catalyst to promote conversion todisulfide oil.

For example, one arrangement of a kerosene sweetening zone includescaustic wash of the kerosene feed for residual H₂S removal. A reactorvessel containing an effective quantity of activated carbon catalystutilizes air in conjunction with the caustic solution to affect theoxidation of mercaptans to disulfides. Caustic is separated from treatedkerosene in the bottom section of the reactor. After water washing,kerosene product passes upwards through one of two parallel salt filtersto remove free water and some soluble water. The kerosene product passesdownward through one of two parallel clay filters for removal of solids, moisture, emulsions and surfactants, so as to ensure that thekerosene product meets haze, color stability and water separationspecifications, for instance, compliant with Jet A specifications.

The second middle distillate fraction 1122 is processed in a dieselhydrotreating zone 1150 in the presence of an effective amount ofhydrogen obtained from recycle within the diesel hydrotreating zone 1150and make-up hydrogen (not shown). In certain embodiments, all or aportion of the make-up hydrogen is derived from the steam crackerhydrogen stream 1232 from the olefins recovery train 1230. The dieselhydrotreating zone 1150 operates under conditions effective for removalof a significant amount of the sulfur and other known contaminants, forinstance, to meet necessary sulfur specifications for the diesel fuelfraction 1154, such as a diesel fuel blending component that can becompliant with Euro V diesel standards. In addition, a hydrotreatednaphtha fraction 1152 (sometimes referred to as wild naphtha) isrecovered from the diesel hydrotreating zone 1150, which is routed tothe steam cracking zone 1220 as one of plural steam cracking feedsources. Effluent off-gases are recovered from the diesel hydrotreatingzone 1150 and are passed to the olefins recovery train, the saturatedgas plant as part of the other gases stream 1134, and/or directly to afuel gas system. LPG can be recovered from the diesel hydrotreating zone1150 and routed to the steam cracking zone, the olefins recovery trainand/or the saturated gas plant. In certain embodiments, the hydrotreatednaphtha fraction 1152 is routed through the crude complex 1105, alone,or in combination with other wild naphtha fractions from within theintegrated process. In embodiments in which hydrotreated naphthafraction 1152 is routed through the crude complex 1105, all or a portionof the LPG produced in the diesel hydrotreating zone 1150 can be passedwith the hydrotreated naphtha fraction 1152, or can be passed directlyto the gas plant 1130, or to a separate gas treatment zone. In certainembodiments, all, a substantial portion or a significant portion of thewild naphtha 1152 is routed to the steam cracking zone 1220 (directly orthrough the crude complex 1105).

The diesel hydrotreating zone 1150 can optionally process otherfractions from within the complex (not shown). In embodiments in which akerosene sweetening zone 1120 is used, all or a portion of the disulfideoil can be additional feed to the diesel hydrotreating zone 1150.Further, all or a portion of the first middle distillate fraction 1116can be additional feed to the diesel hydrotreating zone 1150.Additionally, all or a portion of distillates from a vacuum gas oilhydroprocessing zone, and/or all or a portion of distillates from avacuum residue hydrocracking zone, can be routed to the dieselhydrotreating zone 1150. Any portion of distillates not routed to thediesel hydrotreating zone 1150 can be passed to the crude complex 1105or routed to the steam cracking zone 1220.

In certain embodiments, the diesel hydrotreating zone 1150 alsoprocesses at least a portion of the light coker gas oil 1334 from thecoking zone 1300. Any portion of the light coker gas oil 1334 not routedto the diesel hydrotreating zone 1150 can optionally be passed to a fueloil pool and/or processed in the integrated gas oil hydroprocessingzone. For example, 0-30, 0-25, 0-20, 5-30, 5-25, 5-20, 10-30, 10-25, or10-20 wt % of the total light coker gas oil 1334 from the coking zone1300 can be routed to the diesel hydrotreating zone 1150.

The diesel hydrotreating zone 1150 can contain one or more fixed-bed,ebullated-bed, slurry-bed, moving bed, continuous stirred tank (CSTR) ortubular reactors, in series and/or parallel arrangement, and is operatedunder conditions effective for hydrotreating of the diesel feed 1122,the particular type of reactor, the feed characteristics, the desiredproduct slate and the catalyst selection. In certain embodiments, thediesel hydrotreating zone 1150 contains a layered bed reactor with threecatalyst beds and having inter-bed quench gas, and employs a layeredcatalyst system with the layer of hydrodewaxing catalyst positionedbetween beds of hydrotreating catalyst. Additional equipment, includingexchangers, furnaces, feed pumps, quench pumps, and compressors to feedthe reactor(s) and maintain proper operating conditions, are well knownand are considered part of the diesel hydrotreating zone 1150. Inaddition, equipment including pumps, compressors, high temperatureseparation vessels, low temperature separation vessels and the like toseparate reaction products and provide hydrogen recycle within thediesel hydrotreating zone 1150, are well known and are considered partof the diesel hydrotreating zone 1150.

In certain embodiments, the diesel hydrotreating zone 1150 operatingconditions include:

a reactor temperature (° C.) in the range of from about 270-450,300-450, 320-450, 340-450, 270-435, 300-435, 320-435, 340-435, 270-400,300-400, 320-400, 340-400, 270-380, 300-380, 320-380, 340-360, 270-360,300-360, 320-360 or 340-360;

a hydrogen partial pressure (barg) in the range of from about 30-80,30-70, 30-60, 35-80, 35-70, 35-60, 40-80, 40-70 or 40-60;

a hydrogen gas feed rate (standard liters per liter of hydrocarbon feed,SLt/Lt) of up to about 1000, 700 or 500, in certain embodiments fromabout 200-1000, 200-700, 200-500, 250-1000, 250-700, 250-500, 300-1000,300-700 or 300-500; and

a liquid hourly space velocity (h⁻¹), on a fresh feed basis relative tothe hydrotreating catalysts, in the range of from about 0.1-10.0,0.1-6.0, 0.1-5.0, 0.1-4.0, 0.1-2.0, 0.5-10.0, 0.5-5.0, 0.5-2.0,0.8-10.0, 0.8-6.0, 0.8-5.0, 0.8-4.0, 0.8-2.0, 1.0-10.0, 1.0-6.0,1.0-5.0, 1.0-4.0 or 1.0-2.0.

An effective quantity of hydrotreating catalyst is provided in thediesel hydrotreating zone 1150, including those possessing hydrotreatingfunctionality, including hydrodesulfurization and/orhydrodenitrification, to remove sulfur, nitrogen and other contaminants.Suitable hydrotreating catalysts (sometimes referred to in the industryas “pretreat catalyst”) contain one or more active metal component ofmetals or metal compounds (oxides or sulfides) selected from thePeriodic Table of the Elements IUPAC Groups 6, 7, 8, 9 and 10. One ormore active metal component(s) are typically deposited or otherwiseincorporated on a support, which can include alumina, silica alumina,silica, titania, titania-silica, titania-silicates or combinationsincluding at least one of the foregoing support materials. In certainembodiments, the active metal or metal compound is one or more of Co,Ni, W and Mo, including combinations such as one or more active metalsor metal compounds selected from Co/Mo, Ni/Mo, Ni/W, and Co/Ni/Mo.Combinations of one or more of Co/Mo, Ni/Mo, Ni/W and Co/Ni/Mo can alsobe used, for instance, in plural beds or separate reactors in series.The combinations can be composed of different particles containing asingle active metal species, or particles containing multiple activespecies. In certain embodiments, the catalyst particles have a porevolume in the range of about (cc/gm) 0.15-1.70, 0.15-1.50, 0.30-1.50 or0.30-1.70; a specific surface area in the range of about (m²/g) 100-400,100-350, 100-300, 150-400, 150-350, 150-300, 200-400, 200-350 or200-300; and an average pore diameter of at least about 10, 50, 100,200, 500 or 1000 angstrom units. The active metal(s) or metalcompound(s) are incorporated in an effective concentration, forinstance, in the range of (wt % based on the mass of the oxides,sulfides or metals relative to the total mass of the catalysts) 1-40,1-30, 1-10, 1-5, 2-40, 2-30, 2-10, 3-40, 3-30 or 3-10.

In certain embodiments, an effective quantity of a grading material isadded to remove contaminants such as iron sulfide. In certainembodiments, an effective quantity of hydrodewaxing catalyst is alsoadded to improve cloud point and pour point, generally by conversion ofnormal paraffins into isoparaffins. In such embodiments, effectivehydrodewaxing catalysts include those typically used for isomerizing andcracking paraffinic hydrocarbon feeds to improve cold flow properties,such as catalysts comprising Ni, W, or molecular sieves or combinationsthereof.

Catalyst comprising Ni/W, zeolite with medium or large pore sizes, or acombination thereof are suitable, along with catalyst comprisingaluminosilicate molecular sieves such as zeolites with medium or largepore sizes. Effective commercial zeolites include for instance ZSM-5,ZSM-11, ZSM-12, ZSM-22, ZSM-23, ZSM 35, and zeolites of type beta and Y.Hydrodewaxing catalyst is typically supported on an oxide support suchas Al₂O₃, SiO₂, ZrO2, zeolites, zeolite-alumina, alumina-silica,alumina-silica-zeolite, activated carbon, and mixtures thereof.Effective liquid hourly space velocity values (h⁻¹), on a fresh feedbasis relative to the hydrodewaxing catalyst, are in the range of fromabout 0.1-12.0, 0.1-8.0, 0.1-4.0, 0.5-12.0, 0.5-8.0, 0.5-4.0, 1.0-12.0,1.0-8.0, 1.0-4.0 or 1.6-2.4.

The vacuum gas oil stream 1144 (or separate light and heavy VGO streams,not shown) are processed in a gas oil hydroprocessing zone 1160/1170, inthe presence of an effective amount of hydrogen obtained from recyclewithin the gas oil hydroprocessing zone and make-up hydrogen. In certainembodiments, all or a portion of the make-up hydrogen is derived fromthe steam cracker hydrogen stream 1232 from the olefins recovery train1230. In certain embodiments, all or a portion of the heavy middledistillate fraction, such as a portion of the third middle distillatefraction 1124, for example, atmospheric gas oil from the atmosphericdistillation zone 1110, can also be treated in the gas oilhydroprocessing zone 1160/1170. The heavy middle distillate fraction caninclude a full range atmospheric gas oil, or a fraction thereof such asheavy atmospheric gas oil, and any portion not treated in the gas oilhydroprocessing zone 1160/1170 is separately treated.

Further, a portion of the third middle distillate fraction 1124 can berouted to the gas oil hydroprocessing zone. In certain embodiments, all,a substantial portion, a significant portion or a major portion of thevacuum gas oil stream 1144 is routed to the gas oil hydroprocessing zone1160/1170, and any remainder of the vacuum gas oil can be separatelytreated. In combination, or alternatively with the straight run vacuumgas oil stream 1144, the feed to the gas oil hydroprocessing zone1160/1170 can include a wide range of initial feedstocks obtained fromvarious sources, such as one or more of treated vacuum gas oil,demetallized oil from solvent demetallizing operations, deasphalted oilfrom solvent deasphalting operations, coker gas oils from cokeroperations, cycle oils from delayed coking operations including heavycoker gas oil, and visbroken oils from visbreaking operations. Incertain embodiments in which residue treatment is integrated, all, asubstantial portion, a significant portion or a major portion of gas oilrange products, stream 1188, can be routed to the gas oilhydroprocessing zone 1160/1170, and any remainder can be separatelytreated. The feedstream to the feed gas oil hydroprocessing zone1160/1170 generally has a boiling point range within about 350-800,350-700, 350-600 or 350-565° C.

Ina hydrocracking mode of operation for treatment of the vacuum gas oil,denoted as gas oil hydrocracking zone 1160, the feed is converted byreaction under suitable hydrocracking conditions, and generally producesoff-gas and light ends (not shown), a wild naphtha stream 1162, a dieselfuel fraction 1164, and an unconverted oil fraction 1166. Hydrocrackingprocesses are used commercially in a large number of petroleumrefineries. They are used to process a variety of feeds boiling abovethe atmospheric gas oil range (for example, in the range of about 370 to520° C.) in conventional hydrocracking units and boiling above thevacuum gas oil range (for example, above about 520° C.) in residuehydrocracking units. In general, hydrocracking processes split themolecules of the feed into smaller, i.e., lighter, molecules havinghigher average volatility and economic value. Additionally,hydrocracking processes typically improve the quality of the hydrocarbonfeedstock by increasing the hydrogen-to-carbon ratio and by removingorganosulfur and organonitrogen compounds. The significant economicbenefit derived from hydrocracking processes has resulted in substantialdevelopment of process improvements and more active catalysts.

Three major hydrocracking process schemes include single-stage oncethrough hydrocracking, series-flow hydrocracking with or withoutrecycle, and two-stage recycle hydrocracking. Single-stage once throughhydrocracking is the simplest of the hydrocracker configuration andtypically occurs at operating conditions that are more severe thanhydrotreating processes, and less severe than conventional higherpressure hydrocracking processes. It uses one or more reactors for bothtreating steps and cracking reaction, so the catalyst must be capable ofboth hydrotreating and hydrocracking. This configuration is costeffective, but typically results in relatively low product yields (forexample, a maximum conversion rate of about 50 wt %). Single stagehydrocracking is often designed to maximize mid-distillate yield over asingle or dual catalyst systems. Dual catalyst systems can be used in astacked-bed configuration or in two different reactors. The effluentsare passed to a fractionator column to separate the H₂S, NH₃, lightgases (C₁-C₄), naphtha and diesel products, boiling in the temperaturerange including and below atmospheric gas oil range fractions (forinstance in the temperature range of 36−370° C.). The hydrocarbonsboiling above the atmospheric gas oil range (for instance 370° C.) aretypically unconverted oils.

The gas oil hydrocracking zone 1160 operates under mild, moderate orsevere hydrocracking conditions, and generally produces off-gas andlight ends (not shown), a wild naphtha stream 1162, a diesel fuelfraction 1164, and an unconverted oil fraction 1166. Effluent off-gasesare recovered from the gas oil hydrocracking zone 1160 and are passed tothe olefins recovery train, the saturated gas plant as part of the othergases stream 1134, and/or directly to a fuel gas system. LPG can berecovered from the gas oil hydrocracking zone 1160 and routed to thesteam cracking zone 1220, the olefins recovery train 1230 and/or thesaturated gas plant 1130. The naphtha fraction 1162 is routed to thesteam cracking zone 1220. In certain embodiments, the naphtha fraction1162 is routed through the crude complex 1105, alone, or in combinationwith other wild naphtha fractions from within the integrated process. Inembodiments in which naphtha fraction 1162 is routed through the crudecomplex 1105, all or a portion of the LPG produced in the gas oilhydrocracking zone 1160 can be passed with the naphtha fraction 1162.The unconverted oil fraction 1166 is routed to the coking zone 1300. Thediesel fuel fraction 1164 is recovered as fuel, for instance, as adiesel fuel blending component that can be compliant with Euro V dieselstandards, and can be combined with the diesel fuel fraction 1154 fromthe diesel hydrotreating zone 1150.

Vacuum gas oil hydrocracking zone 1160 can operate under mild, moderateor severe conditions, depending on factors including the feedstock andthe desired degree of conversion. Such conditions are effective forremoval of a significant amount of the sulfur and other knowncontaminants, and for conversion of the feed(s) into a major proportionof hydrocracked products and minor proportions of off-gases, light endsand unconverted product. A suitable vacuum gas oil hydrocracker zone1160 can include, but is not limited to, systems based on technologycommercially available from Honeywell UOP, US; Chevron Lummus Global LLC(CLG), US; Axens, FR; Shell Catalysts & Technologies, US, or HaldorTopsoe, DK.

The gas oil hydrocracking zone 1160 can contain one or more fixed-bed,ebullated-bed, slurry-bed, moving bed, continuous stirred tank (CSTR) ortubular reactors, in series and/or parallel arrangement, and is operatedunder conditions effective for gas oil hydrocracking, the particulartype of reactor, the feed characteristics, the desired product slate andthe catalyst selection. Additional equipment, including exchangers,furnaces, feed pumps, quench pumps, and compressors to feed thereactor(s) and maintain proper operating conditions, are well known andare considered part of the gas oil hydrocracking zone 1160. In addition,equipment, including pumps, compressors, high temperature separationvessels, low temperature separation vessels and the like to separatereaction products and provide hydrogen recycle within the gas oilhydrocracking zone 1160, are well known and are considered part of thegas oil hydrocracking zone 1160.

Series-flow hydrocracking with or without recycle is one of the mostcommonly used configurations. It uses one reactor (containing bothtreating and cracking catalysts) or two or more reactors for bothtreating and cracking reaction steps. In a series-flow configuration theentire hydrocracked product stream from the first reaction zone,including light gases (typically C₁-C₄, H₂S, NH₃) and all remaininghydrocarbons, are sent to the second reaction zone. Unconverted bottomsfrom the fractionator column are recycled back into the first reactorfor further cracking. This configuration converts heavy crude oilfractions such as vacuum gas oil, into light products and has thepotential to maximize the yield of naphtha, kerosene and/or diesel rangehydrocarbons, depending on the recycle cut point used in thedistillation section.

Two-stage recycle hydrocracking uses two reactors and unconvertedbottoms from the fractionation column are passed to the second reactorfor further cracking. Since the first reactor accomplishes bothhydrotreating and hydrocracking, the feed to the second reactor isvirtually free of ammonia and hydrogen sulfide. This permits the use ofhigh performance zeolite catalysts which are susceptible to poisoning bysulfur or nitrogen compounds.

Effective hydrocracking catalyst generally contain about 5-40 wt % basedon the weight of the catalyst, of one or more active metal component ofmetals or metal compounds (oxides or sulfides) selected from thePeriodic Table of the Elements IUPAC Groups 6, 7, 8, 9 and 10. Incertain embodiments, the active metal component is one or more of Mo, W,Co or Ni. The active metal component is typically deposited or otherwiseincorporated on a support, such as amorphous alumina, amorphous silicaalumina, zeolites, or combinations thereof. In certain embodiments,alone or in combination with the above metals, Pt group metals such asPt and/or Pd, may be present as a hydrogenation component, generally inan amount of about 0.1-2 wt % based on the weight of the catalyst.

Exemplary products from the gas oil hydrocracking zone 1160 include27-99, 27-90, 27-82, 27-80, 27-75, 27-52, 27-48, 30-99, 30-90, 30-82,30-80, 30-75, 30-52, 30-48, 48-99, 48-90, 48-82, 48-80, 48-75, 48-52,78-99, 78-90, 78-85, 80-90 or 80-99 wt % of effluent (relative to thefeed to the gas oil hydrocracking zone 1160) boiling at or below theatmospheric residue end boiling point, such as 370° C., including LPG,kerosene, naphtha, and atmospheric gas oil range components. Theremaining bottoms fraction is the unconverted oil fraction all or aportion of which can be effectively integrated as feed to the cokingzone 1300 as described herein.

In certain embodiments, a gas oil hydrocracking zone 1160 operates as aonce-through single reactor hydrocracking system, and typically includesa reaction zone and a fractionating zone, which can serve as a mildconversion or partial conversion hydrocracker. A reaction zone in aonce-through single reactor system generally includes one or more inletsin fluid communication with the feedstock 1144 and optionally all or anyportion of stream 1124, and a source of hydrogen gas. One or moreoutlets of reaction zone that discharge an effluent stream are in fluidcommunication with one or more inlets of the fractionating zone(typically including one or more high pressure and/or low pressureseparation stages therebetween for recovery of recycle hydrogen). Thefractionating zone typically includes one or more outlets fordischarging gases, typically H₂, H₂S, NH₃, and light hydrocarbons(C₁-C₄); one or more outlets for recovering products, such as naphtha1162 and diesel range products 1164, and one or more outlets fordischarging bottoms 1166 including hydrocarbons boiling above theatmospheric gas oil range (for instance 370° C.) which is then routed tothe coking zone 1300. In certain embodiments, the temperature cut pointfor the bottoms stream (and correspondingly the end point for theproducts) is a range corresponding to the upper temperature limit of thediesel range products 1164.

In operation of a hydrocracking zone 1160 operating as a once-throughsingle reactor hydrocracking system, the feedstock and hydrogen arecharged to the reaction zone. The hydrogen is provided in an effectivequantity to support the requisite degree of hydrocracking, feed type,and other factors, and can be any combination including recycle hydrogenfrom optional gas separation subsystems associated with reaction zone,hydrogen derived from the fractionator gas stream, and/or make-uphydrogen, if necessary. In certain embodiments, a reaction zone cancontain multiple catalyst beds and can receive one or more quenchhydrogen streams between the beds.

The reaction effluent stream contains converted, partially converted andunconverted hydrocarbons. Reaction effluents are passed to thefractionating zone (optionally after one or more high pressure and lowpressure separation stages to recover recycle hydrogen), generally torecover gas and liquid products and by-products, and separate a bottomsfraction.

The gas stream, typically containing H₂, H₂S, NH₃, and lighthydrocarbons (C₁-C₄), is discharged and recovered, and can be furtherprocessed, for instance, in the olefins recovery train, the saturatedgas plant as part of the other gases stream 1134, and/or integrateddirectly in a fuel gas system. LPG can be recovered and routed to thesteam cracking zone, the olefins recovery train and/or the saturated gasplant. One or more cracked product streams are discharged viaappropriate outlets of the fractionator as the naphtha 1162 and dieselrange products 1164. In certain embodiments, a fractionating zone canoperate as a flash vessel to separate heavy components at a suitable cutpoint, for example, a range corresponding to the upper temperature rangeof the diesel range products 1164. In certain embodiments, a suitablecut point is in the range of 350 to 450° C., 360 to 450° C., 370 to 450°C., 350 to 400° C., 360 to 400° C., 370 to 400° C., 350 to 380° C., or360 to 380° C.

The reactor arrangement in the gas oil hydrocracking zone 1160 operatingas a once-through single reactor hydrocracking system can contain one ormore fixed-bed, ebullated-bed, slurry-bed, moving bed, continuousstirred tank (CSTR), or tubular reactors, which can be in parallelarrangement, and is operated under conditions effective for gas oilhydrocracking, the particular type of reactor, the feed characteristics,the desired product slate and the catalyst selection. The once-throughsingle reactor hydrocracking system can operate in a mild hydrocrackingmode of operation or a partial conversion mode of operation. Additionalequipment, including exchangers, furnaces, feed pumps, quench pumps, andcompressors to feed the reactor(s) and maintain proper operatingconditions, are well known and are considered part of the once-throughsingle reactor hydrocracking system. In addition, equipment, includingpumps, compressors, high temperature separation vessels, low temperatureseparation vessels and the like to separate reaction products andprovide hydrogen recycle within the once-through single reactorhydrocracking system, are well known and are considered part of theonce-through single reactor hydrocracking system.

In certain embodiments, operating conditions for the reactor(s) in ahydrocracking zone 1160 using a once-through (single stage withoutrecycle) configuration and operating in a mild hydrocracking modeinclude:

a reactor temperature (° C.) in the range of from about 300-500,300-475, 300-450, 330-500, 330-475 or 330-450;

a hydrogen partial pressure (barg) in the range of from about 15-100,15-70, 15-60, 15-50, 20-100, 20-70, 20-60, 20-50, 30-100, 30-70, 30-60or 30-50;

a hydrogen gas feed rate (standard liters per liter of hydrocarbon feed,SLt/Lt) of up to about 2500, 2000 or 1500, in certain embodiments fromabout 800-2500, 800-2000, 800-1500, 1000-2500, 1000-2000 or 1000-1500;and

a liquid hourly space velocity (h⁻¹), on a fresh feed basis relative tothe hydrotreating catalysts, in the range of from about 0.1-10.0,0.1-6.0, 0.1-5.0, 0.1-4.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0,0.5-10.0, 0.5-6.0, 0.5-5.0, 0.5-4.0, 0.5-3.0 or 0.5-2.0.

Under the above conditions and catalyst selections, exemplary productsfrom the gas oil hydrocracking zone 1160 operating as a once-throughsingle reactor system, and operating in a mild hydrocracking mode ofoperation, include 27-52, 27-48, 30-50 or 30-52 wt % of effluent(relative to the feed to the gas oil hydrocracking zone 1160) boiling ator below the atmospheric residue end boiling point, such as 370° C.,including LPG and distillate product components (naphtha 1162 and dieselrange products 1164). The remaining bottoms fraction is the unconvertedoil fraction.

In certain embodiments, operating conditions for the reactor(s) in ahydrocracking zone 1160 using a once-through (single stage withoutrecycle) configuration and operating in a partial conversion modeinclude:

a reactor temperature (° C.) in the range of from about 300-500,300-475, 300-450, 330-500, 330-475 or 330-450;

a hydrogen partial pressure (barg) in the range of from about 50-120,50-100, 50-90, 60-120, 60-100, 60-90, 70-120, 70-100 or 70-90;

a hydrogen gas feed rate (standard liters per liter of hydrocarbon feed,SLt/Lt) of up to about 2500, 2000 or 1500, in certain embodiments fromabout 800-2500, 800-2000, 800-1500, 1000-2500, 1000-2000 or 1000-1500;and

a liquid hourly space velocity (h⁻¹), on a fresh feed basis relative tothe hydrotreating catalysts, in the range of from about 0.1-10.0,0.1-6.0, 0.1-5.0, 0.1-4.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0,0.5-10.0, 0.5-6.0, 0.5-5.0, 0.5-4.0, 0.5-3.0 or 0.5-2.0.

Under the above conditions and catalyst selections, exemplary productsfrom the gas oil hydrocracking zone 1160 operating as a once-throughsingle reactor system, and operating as a partial conversionhydrocracker, include 48-82, 50-80, 48-75, or 50-75 wt % of effluent(relative to the feed to the gas oil hydrocracking zone 1160) boiling ator below the atmospheric residue end boiling point, such as 370° C.,including LPG and distillate product components (naphtha 1162 and dieselrange products 1164). The remaining bottoms fraction is the unconvertedoil fraction that is routed to the coking zone 1300 as described herein.

In certain embodiments, a gas oil hydrocracking zone 1160 operates as aseries-flow hydrocracking system with recycle to the first reactor zone,the second reactor zone, or both the first and second reactor zones. Ingeneral, series flow hydrocracking zone includes a first reaction zone,a second reaction zone and a fractionating zone. The first reaction zonegenerally includes one or more inlets in fluid communication with thefeedstock 1144 and optionally all or any portion of stream 1124, asource of hydrogen gas, in certain embodiments a recycle streamcomprising all or a portion of the fractionating zone bottoms stream(and optionally a portion of the fractionating zone products). One ormore outlets of the first reaction zone that discharge an effluentstream is in fluid communication with one or more inlets of the secondreaction zone. In certain embodiments, the effluents are passed to thesecond reaction zone without separation of any excess hydrogen and lightgases. In optional embodiments, one or more high pressure and lowpressure separation stages are provided between the first and secondreaction zones for recovery of recycle hydrogen. The second reactionzone generally includes one or more inlets in fluid communication withone or more outlets of the first reaction zone, optionally a source ofadditional hydrogen gas, and in certain embodiments a recycle streamcomprising all or a portion of the fractionating zone bottoms stream,and optionally a portion of the fractionating zone products. One or moreoutlets of the second reaction zone that discharge an effluent stream isin fluid communication with one or more inlets of the fractionating zone(optionally having one or more high pressure and low pressure separationstages in between the second reaction zone and the fractionating zonefor recovery of recycle hydrogen). The fractionating zone includes oneor more outlets for discharging gases, typically H₂, H₂S, NH₃, and lighthydrocarbons (C₁-C₄); one or more outlets for recovering distillateproducts, such as naphtha 1162 and diesel range products 1164; and oneor more outlets for discharging bottoms 1166 including hydrocarbonsboiling above the atmospheric gas oil range (for instance about 370°C.), that is routed to the coking zone 1300 as described herein. Incertain embodiments, the temperature cut point for the bottoms stream(and correspondingly the end point for the products) is a rangecorresponding to the upper temperature limit of the diesel rangeproducts 1164.

In operation of a hydrocracking zone 1160 operating as a series flowhydrocracking system with recycle, the feedstock and hydrogen arecharged to the first reaction zone. The hydrogen is provided in aneffective quantity to support the requisite degree of hydrocracking,feed type, and other factors, and can be any combination includingrecycle hydrogen from optional gas separation subsystems associated withone or both of the reaction zones, derived from the fractionator gasstream, and/or make-up hydrogen. In certain embodiments, one or both ofthe reaction zones can contain multiple catalyst beds and can receiveone or more quench hydrogen streams between the beds.

The first reaction zone operates under effective conditions forproduction of a reaction effluent stream which is passed to the secondreaction zone (optionally after one or more high pressure and lowpressure separation stages to recover recycle hydrogen), optionallyalong with an additional hydrogen stream. The second reaction zoneoperates under conditions effective for production of the secondreaction effluent stream, which contains converted, partially convertedand unconverted hydrocarbons. The second reaction effluent stream ispassed to the fractionating zone, generally to recover gas and liquidproducts and by-products, and separate a bottoms fraction. The gasstream, typically containing H₂, H₂S, NH₃, and light hydrocarbons(C₁-C₄), is discharged and recovered, and can be further processed, forinstance, in the olefins recovery train, the saturated gas plant as partof the other gases stream 1134, and/or integrated directly in a fuel gassystem. LPG can be recovered and routed to the steam cracking zone, theolefins recovery train and/or the saturated gas plant. One or morecracked product streams are discharged via appropriate outlets of thefractionator as the naphtha 1162 and diesel range products 1164. Incertain embodiments, a portion of the diesel range products 1164 can beintegrated with the recycle streams to the reactors, for instance, tomaximize naphtha feed to the steam cracker. In certain embodiments, afractionating zone can operate as a flash vessel to separate heavycomponents at a suitable cut point, for example, a range correspondingto the upper temperature range of the diesel range products 1164. Incertain embodiments, a suitable cut point is in the range of 350 to 450°C., 360 to 450° C., 370 to 450° C., 350 to 400° C., 360 to 400° C., 370to 400° C., 350 to 380° C., or 360 to 380° C.

In certain embodiments at least a portion of the fractionator bottomsstream from the reaction effluent is recycled to the first or secondreaction zones. In certain embodiments, a portion of the fractionatorbottoms from the reaction effluent is removed as bleed stream, which canbe about 0-10 vol %, 1-10 vol %, 1-5 vol % or 1-3 vol % of thefractionator bottoms. For instance, a recycle stream to the firstreaction zone can comprise 0 to 100 vol %, 0 to about 80 vol %, or 0 toabout 50 vol % of the fractionator bottoms stream, and a recycle streamto the second reaction zone can comprise 0 to 100 vol %, 0 to about 80vol %, or 0 to about 50 vol % of the fractionator bottoms stream. Incertain embodiments, in which the recycle is at or approaches 100 vol %,recycle of the unconverted oil increases the yield of products suitableas feed to the steam cracking zone 1220.

The reactor arrangement in the gas oil hydrocracking zone 1160 operatingas a series flow hydrocracking system with recycle can contain one ormore fixed-bed, ebullated-bed, slurry-bed, moving bed, continuousstirred tank (CSTR), or tubular reactors, which can be in parallelarrangement, and are operated under conditions effective for gas oilhydrocracking, the particular type of reactor, the feed characteristics,the desired product slate and the catalyst selection. Additionalequipment, including exchangers, furnaces, feed pumps, quench pumps, andcompressors to feed the reactor(s) and maintain proper operatingconditions, are well known and are considered part of the series flowhydrocracking system. In addition, equipment, including pumps,compressors, high temperature separation vessels, low temperatureseparation vessels and the like to separate reaction products andprovide hydrogen recycle within the series flow hydrocracking system,are well known and are considered part of the series flow hydrocrackingsystem.

In certain embodiments, operating conditions for the first reactor(s) ina hydrocracking zone 1160 using a once-through series configuration(with recycle) operating in a partial conversion mode of operationinclude:

a reactor temperature (° C.) in the range of from about 300-500,300-475, 300-450, 330-500, 330-475 or 330-450;

a hydrogen partial pressure (barg) in the range of from about 50-150,50-120, 50-100, 50-90, 60-150, 60-120, 60-100, 60-90, 60-80, 70-150,70-120 or 70-100;

a hydrogen gas feed rate (standard liters per liter of hydrocarbon feed,SLt/Lt) of up to about 2500, 2000 or 1500, in certain embodiments fromabout 800-2500, 800-2000, 800-1500, 1000-2500, 1000-2000 or 1000-1500;and

a liquid hourly space velocity (h⁻¹), on a fresh feed basis relative tothe hydrotreating catalysts, in the range of from about 0.1-10.0,0.1-6.0, 0.1-5.0, 0.1-4.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0,0.5-10.0, 0.5-6.0, 0.5-5.0, 0.5-4.0, 0.5-3.0 or 0.5-2.0.

In certain embodiments, operating conditions for the second reactor(s)in a hydrocracking zone 1160 using a once-through series configuration(with recycle) operating in a partial conversion mode of operationinclude:

a reactor temperature (° C.) in the range of from about 300-500,300-475, 300-450, 330-500, 330-475 or 330-450;

a hydrogen partial pressure (barg) in the range of from about 50-150,50-120, 50-100, 50-90, 60-150, 60-120, 60-100, 60-90, 60-80, 70-150,70-120 or 70-100;

a hydrogen gas feed rate (standard liters per liter of hydrocarbon feed,SLt/Lt) of up to about 2500, 2000 or 1500, in certain embodiments fromabout 800-2500, 800-2000, 800-1500, 1000-2500, 1000-2000 or 1000-1500;and

a liquid hourly space velocity (h⁻¹), on a fresh feed basis relative tothe hydrotreating catalysts, in the range of from about 0.1-10.0,0.1-6.0, 0.1-5.0, 0.1-4.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0,0.5-10.0, 0.5-6.0, 0.5-5.0, 0.5-4.0, 0.5-3.0 or 0.5-2.0.

Under the above conditions and catalyst selections, exemplary productsfrom a hydrocracking zone 1160 using a series-flow configuration (withrecycle) and operating as a partial conversion hydrocracker include48-82, 50-80, 48-75 or 50-75 wt % of effluent (relative to the feed tothe hydrocracking zone 1160) boiling at or below the atmospheric residueend boiling point, such as 370° C., including LPG and distillate productcomponents (naphtha 1162 and diesel range products 1164). The remainingbottoms fraction is the unconverted oil fraction that is routed to thecoking zone 1300 as described herein.

In certain embodiments, a gas oil hydrocracking zone 1160 operates as atwo-stage hydrocracking system with recycle, and typically includes afirst reaction zone, a second reaction zone and a fractionating zone.The first reaction zone generally includes one or more inlets in fluidcommunication with the feedstock 1144 and optionally all or any portionof stream 1124, and a source of hydrogen gas. One or more outlets of thefirst reaction zone that discharge an effluent stream is in fluidcommunication with one or more inlets of the fractionating zone(optionally having one or more high pressure and low pressure separationstages therebetween for recovery of recycle hydrogen. The fractionatingzone includes one or more outlets for discharging gases, typically H₂S,NH₃, and light hydrocarbons (C₁-C₄); one or more outlets for recoveringdistillate product, such as naphtha 1162 and diesel range 1164; and oneor more outlets for discharging bottoms 1166 including hydrocarbonsboiling above the atmospheric gas oil range (for instance about 370° C.)that is routed to the coking zone 1300 as described herein. In certainembodiments, the temperature cut point for the bottoms stream (andcorrespondingly the end point for the products) is a range correspondingto the upper temperature limit of the diesel range products 1164. Thefractionating zone bottoms outlet is in fluid communication with the oneor more inlets of the second reaction zone for receiving a recyclestream, which is all or a portion of the bottoms stream. In certainoptional embodiments, a portion of the bottoms stream is in fluidcommunication with one or more inlets of the first reaction zone. Thesecond reaction zone generally includes one or more inlets in fluidcommunication with the fractionating zone bottoms outlet portion and asource of hydrogen gas. One or more outlets of the second reaction zonethat discharge effluent stream are in fluid communication with one ormore inlets of the fractionating zone (optionally having one or morehigh pressure and low pressure separation stages therebetween forrecovery of recycle hydrogen).

In operation of a hydrocracking zone 1160 operating as a two-stagehydrocracking system with recycle, the feedstock and hydrogen arecharged to the first reaction zone. The hydrogen is provided in aneffective quantity to support the requisite degree of hydrocracking,feed type, and other factors, and can be any combination includingrecycle hydrogen from optional gas separation subsystems associated withthe reaction zones, derived from the fractionator gas stream, and/ormake-up hydrogen, if necessary. In certain embodiments, a reaction zonecan contain multiple catalyst beds and can receive one or more quenchhydrogen streams between the beds.

The first reaction zone operates under effective conditions forproduction of a reaction effluent stream which is passed to thefractionating zone (optionally after one or more high pressure and lowpressure separation stages to recover recycle hydrogen) generally torecover gas and liquid products and by-products, and separate a bottomsfraction. The gas stream, typically containing H₂, H₂S, NH₃, and lighthydrocarbons (C₁-C₄), is discharged and recovered, and can be furtherprocessed, for instance, in the olefins recovery train, the saturatedgas plant as part of the other gases stream 1134, and/or integrateddirectly in a fuel gas system. LPG can be recovered and routed to thesteam cracking zone, the olefins recovery train and/or the saturated gasplant.

One or more cracked product streams are discharged via appropriateoutlets of the fractionator as the naphtha 1162 and diesel rangeproducts 1164. In certain embodiments, a portion of the diesel rangeproducts 1164 can be integrated with the feed to the second stagereactor, for instance, to maximize naphtha feed to the steam cracker. Incertain embodiments, a fractionating zone can operate as a flash vesselto separate heavy components at a suitable cut point, for example, arange corresponding to the upper temperature range of the diesel rangeproducts 1164. In certain embodiments, a suitable cut point is in therange of 350 to 450° C., 360 to 450° C., 370 to 450° C., 350 to 400° C.,360 to 400° C., 370 to 400° C., 350 to 380° C., or 360 to 380° C.

In certain embodiments at least a portion of the fractionator bottomsstream from the reaction effluent is recycled to the first or secondreaction zones. In certain embodiments, a portion of the fractionatorbottoms from the reaction effluent is removed as bleed stream, which canbe about 0-10 vol %, 1-10 vol %, 1-5 vol % or 1-3 vol % of thefractionator bottoms. In certain embodiments, all or a portion of thebottoms stream is recycled to the second reaction zone, the firstreaction zone, or both the first and second reaction zones. Forinstance, a recycle stream to the first reaction zone can comprise 0 to100 vol %, 0 to about 80 vol %, or 0 to about 50 vol % of thefractionator bottoms stream, and a recycle stream to the second reactionzone can comprise 0 to 100 vol %, 0 to about 80 vol %, or 0 to about 50vol % of the fractionator bottoms stream. In certain embodiments, inwhich the recycle is at or approaches 100 vol %, recycle of theunconverted oil increases the yield of products suitable as feed to thesteam cracking zone 1220.

The second reaction zone operates under conditions effective forproduction of the reaction effluent stream, which contains converted,partially converted and unconverted hydrocarbons. The second stagereaction effluent is passed to the fractionating zone, optionallythrough one or more gas separators to recover recycle hydrogen andremove certain light gases.

The reactor arrangement in the gas oil hydrocracking zone 1160 operatingas a two-stage hydrocracking system with recycle can contain one or morefixed-bed, ebullated-bed, slurry-bed, moving bed, continuous stirredtank (CSTR), or tubular reactors, which can be in parallel arrangement,and are operated under conditions effective for gas oil hydrocracking,the particular type of reactor, the feed characteristics, the desiredproduct slate and the catalyst selection. Additional equipment,including exchangers, furnaces, feed pumps, quench pumps, andcompressors to feed the reactor(s) and maintain proper operatingconditions, are well known and are considered part of the two-stagehydrocracking system. In addition, equipment, including pumps,compressors, high temperature separation vessels, low temperatureseparation vessels and the like to separate reaction products andprovide hydrogen recycle within the two-stage hydrocracking system, arewell known and are considered part of the two-stage hydrocrackingsystem.

In certain embodiments, operating conditions for the first stagereactor(s) in a hydrocracking zone 1160 using a two-stage (with recycle)configuration operating in a full conversion mode of operation include:

a reactor temperature (° C.) in the range of from about 300-500,300-475, 300-450, 330-500, 330-475 or 330-450;

a hydrogen partial pressure (barg) in the range of from about 80-170,80-150, 80-140, 80-130, 90-170, 90-150, 90-140, 90-130, 100-170,100-150, 100-140, 100-130, 110-170, 110-150, 110-140, or 110-130;

a hydrogen gas feed rate (standard liters per liter of hydrocarbon feed,SLt/Lt) of up to about 2500, 2000 or 1500, in certain embodiments fromabout 800-2500, 800-2000, 800-1500, 1000-2500, 1000-2000 or 1000-1500;and

a liquid hourly space velocity (h⁻¹), on a fresh feed basis relative tothe hydrotreating catalysts, in the range of from about 0.1-10.0,0.1-6.0, 0.1-5.0, 0.1-4.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0,0.5-10.0, 0.5-6.0, 0.5-5.0, 0.5-4.0, 0.5-3.0 or 0.5-2.0.

In certain embodiments, operating conditions for the second stagereactor(s) in a hydrocracking zone 1160 using a two-stage (with recycle)configuration operating in a full conversion mode of operation include:

a reactor temperature (° C.) in the range of from about 300-500,300-475, 300-450, 330-500, 330-475 or 330-450;

a hydrogen partial pressure (barg) in the range of from about 80-170,80-150, 80-140, 80-130, 90-170, 90-150, 90-140, 90-130, 100-170,100-150, 100-140, 100-130, 110-170, 110-150, 110-140, or 110-130;

a hydrogen gas feed rate (standard liters per liter of hydrocarbon feed,SLt/Lt) of up to about 2500, 2000 or 1500, in certain embodiments fromabout 800-2500, 800-2000, 800-1500, 1000-2500, 1000-2000 or 1000-1500;and

a liquid hourly space velocity (h⁻¹), on a fresh feed basis relative tothe hydrotreating catalysts, in the range of from about 0.1-10.0,0.1-6.0, 0.1-5.0, 0.1-4.0, 0.1-2.0, 0.3-10.0, 0.3-5.0, 0.3-2.0,0.5-10.0, 0.5-6.0, 0.5-5.0, 0.5-4.0, 0.5-3.0 or 0.5-2.0.

Under the above conditions and catalyst selections, exemplary productsfrom a hydrocracking zone 1160 using a two-stage hydrocracker (withrecycle) configuration in a full conversion mode include 78-99, 78-90,78-85, 80-90 or 80-99 wt % of effluent (relative to the feed to thehydrocracking zone 1160 boiling at or below the atmospheric residue endboiling point, such as 370° C., including LPG, and distillate productcomponents (naphtha 1162 and diesel range products 1164). The remainingbottoms fraction is the unconverted oil fraction that is routed to thecoking zone 1300 as described herein.

In a hydrotreating mode of operation for treatment of the vacuum gasoil, denoted as gas oil hydrotreating zone 1170, the feed is convertedby reaction under suitable hydrotreating conditions, and generallyproduces off-gas and light ends (not shown), a wild naphtha stream 1172and hydrotreated gas oil stream 1176. Effluent off-gases are recoveredfrom the gas oil hydrotreating zone 1170 and are passed to the olefinsrecovery train, the saturated gas plant as part of the other gasesstream 1134, and/or directly to a fuel gas system. LPG can be recoveredfrom the gas oil hydrotreating zone 1170 and routed to the steamcracking zone, the olefins recovery train and/or the saturated gasplant. The naphtha fraction 1172 is routed to the steam cracking zone1220. In certain embodiments, the hydrotreated naphtha fraction 1172 isrouted through the crude complex 1105, alone, or in combination withother wild naphtha fractions from within the integrated process. Inembodiments in which hydrotreated naphtha fraction 1172 is routedthrough the crude complex 1105, all or a portion of the LPG produced inthe gas oil hydrotreating zone 1170 can be passed with the hydrotreatednaphtha fraction 1172. Hydrotreated gas oil 1176 is separately treated.In certain embodiments, in addition to or in conjunction with thehydrotreated naphtha fraction 1172, all or a portion of the hydrotreateddistillates and naphtha from the gas oil hydrotreating zone 1170 arepassed to the diesel hydrotreating zone 1150. In additional embodiments,a middle distillates stream 1164 is also recovered, for instance, asused as a diesel fuel blending component.

The gas oil hydrotreating zone 1170 can operate under mild, moderate orsevere conditions, depending on factors including the feedstock and thedesired degree of conversion. Such conditions are effective for removalof a significant amount of the sulfur and other known contaminants, andfor conversion of the feed(s) into a major proportion of hydrotreatedgas oil 1176 that is routed to the coking zone 1300 as described herein,and minor proportions of off-gases, light ends, and hydrotreated naphtha1172 that is routed to the steam cracking zone 1220 (optionally via thecrude complex 1105). The hydrotreated gas oil fraction 1176 generallycontains the portion of the gas oil hydrotreating zone 1170 effluentthat is at or above the AGO, H-AGO or VGO range.

The gas oil hydrotreating zone 1170 can contain one or more fixed-bed,ebullated-bed, slurry-bed, moving bed, continuous stirred tank (CSTR) ortubular reactors, in series and/or parallel arrangement, and is operatedunder conditions effective for gas oil hydrotreating, the particulartype of reactor, the feed characteristics, the desired product slate andthe catalyst selection. Additional equipment, including exchangers,furnaces, feed pumps, quench pumps, and compressors to feed thereactor(s) and maintain proper operating conditions, are well known andare considered part of the gas oil hydrotreating zone 1170. In addition,equipment, including pumps, compressors, high temperature separationvessels, low temperature separation vessels and the like to separatereaction products and provide hydrogen recycle within the gas oilhydrotreating zone 1170, are well known and are considered part of thegas oil hydrotreating zone 1170.

An effective quantity of catalyst is provided in the gas oilhydrotreating zone 1170, including those possessing hydrotreatingfunctionality, for hydrodesulfurization and hydrodenitrification. Suchcatalysts generally contain one or more active metal component of metalsor metal compounds (oxides or sulfides) selected from the Periodic Tableof the Elements IUPAC Groups 6, 7, 8, 9 and 10. In certain embodiments,the active metal component is one or more of Co, Ni, W and Mo. Theactive metal component is typically deposited or otherwise incorporatedon a support, such as amorphous alumina, amorphous silica alumina,zeolites, or combinations thereof. In certain embodiments, the catalystused in the gas oil hydrotreating zone 1170 includes one or more bedsselected from Co/Mo, Ni/Mo, Ni/W, and Co/Ni/Mo. Combinations of one ormore beds of Co/Mo, Ni/Mo, Ni/W and Co/Ni/Mo can also be used. Thecombinations can be composed of different particles containing a singleactive metal species, or particles containing multiple active species.In certain embodiments, a combination of Co/Mo catalyst and Ni/Mocatalyst are effective for hydrodesulfurization andhydrodenitrification. One or more series of reactors can be provided,with different catalysts in the different reactors of each series. Forinstance, a first reactor includes Co/Mo catalyst and a second reactorincludes Ni/Mo catalyst.

In additional embodiments, an effective quantity of hydrodemetallizationalso can be added. Such catalysts generally contain one or more activemetal component of metals or metal compounds (oxides or sulfides)selected from the Periodic Table of the Elements IUPAC Groups 6, 7, 8, 9and 10. In certain embodiments, the active metal component is one ormore of Ni and Mo. The active metal component is typically deposited orotherwise incorporated on a support such as gamma alumina.

In certain embodiments, the gas oil hydrotreating zone 1170 operatingconditions include:

a reactor temperature (° C.) in the range of from about 300-440,300-400, 300-390, 310-440, 310-400, 310-390, 320-440, 320-400 or320-390;

a hydrogen partial pressure (barg) in the range of from about 30-100,30-80, 30-60, 40-100, 40-80, 40-60, 50-100, 50-80 or 50-60;

a hydrogen gas feed rate (standard liters per liter of hydrocarbon feed,SLt/Lt) of up to about 1000, 750 or 500, in certain embodiments fromabout 100-1000, 100-750, 100-500, 200-1000, 200-750, 200-500, 300-1000,300-750 or 300-500; and

a liquid hourly space velocity (h⁻¹), on a fresh feed basis relative tothe hydrotreating catalysts, in the range of from about 0.5-10.0,0.5-5.0, 0.5-4.0, 1.0-10.0, 1.0-5.0, 1.0-4.0, 2.0-10.0, 2.0-5.0 or2.0-4.0.

Under the above conditions and catalyst selections, exemplary productsfrom the gas oil hydrotreating zone 1170 include 1-30, 5-30, 2-27 or5-27 wt % of effluent (relative to the feed to the gas oil hydrotreatingzone 1170) boiling at or below the atmospheric residue end boilingpoint, such as 370° C., including LPG, kerosene, naphtha, andatmospheric gas oil range components. The remaining bottoms fraction isthe hydrotreated gas oil fraction.

In additional embodiments, the gas oil hydrotreating zone 1170 canoperate under conditions effective for feed conditioning and to maximizetargeted conversion to petrochemicals in the steam cracker complex.Accordingly, in certain embodiments severity conditions are selectedthat achieve objectives differing from those used for conventionalrefinery operations. That is, while typical VGO hydrotreating operateswith less emphasis on conservation of liquid product yield, in thepresent embodiment VGO hydrotreating operates to produce a higher yieldof lighter products which are intentionally recovered to maximizechemicals yield. In embodiments to maximize conversion topetrochemicals, the gas oil hydrotreating zone 1170 operating conditionsinclude:

a reactor temperature (° C.) in the range of from about 320-440,320-420, 320-410, 330-440, 330-420, 330-410, 330-400, 340-440, 340-420,340-410 or 340-400;

a hydrogen partial pressure (barg) in the range of from about 40-100,40-90, 40-80, 45-100, 45-90, 45-80, 50-100, 50-90 or 50-80;

a hydrogen gas feed rate (standard liters per liter of hydrocarbon feed,SLt/Lt) of up to about 1000, 900 or 800, in certain embodiments fromabout 300-1000, 300-900, 300-800, 400-1000, 400-900, 400-800, 500-1000,500-900 or 500-800; and

a liquid hourly space velocity (h⁻¹), on a fresh feed basis relative tothe hydrotreating catalysts, in the range of from about 0.2-4.0,0.2-3.0, 0.2-2.0, 0.5-4.0, 0.5-3.0, 0.5-2.0, 1.0-4.0, 1.0-3.0 or1.0-2.0.

Under the above conditions and catalyst selections, exemplary productsfrom the gas oil hydrotreating zone 1170 operating under conditionseffective for feed conditioning and to maximize targeted conversion topetrochemicals in the steam cracker complex include 20-30, 22-28, 23-27or 24-26 wt % of effluent (relative to the feed to the gas oilhydrotreating zone 1170) boiling at or below the atmospheric residue endboiling point, such as 370° C., including LPG, kerosene, naphtha, andatmospheric gas oil range components. The remaining bottoms fraction isthe hydrotreated gas oil fraction.

In certain embodiments, the gas oil hydrotreating zone 1170 contains oneor more trains of reactors, with a first reactor having two catalystbeds with two quench streams including an inter-bed quench stream, and asecond reactor (lag reactor) having one catalyst bed with a quenchstream. In high capacity operations, two or more parallel trains ofreactors are utilized. In such embodiments, the flow in gas oilhydrotreating zone 1170 is split after the feed pump into paralleltrains, wherein each train contains feed/effluent heat exchangers, feedheater, a reactor and the hot separator. The trains recombine after thehot separators. Tops from the hot separators are combined and passed toa cold separator. Bottoms from the hot separators are passed to a hotflash drum. Bottoms from the cold separator and tops from the hot flashdrum are passed to a low pressure flash drum to remove off-gasses. Hotflash liquid bottoms and low pressure flash bottoms are passed to astripper to recover hydrotreated gas oil and wild naphtha. Tops from thecold separator are subjected to absorption and amine scrubbing. Recyclehydrogen is recovered and passed (along with make-up hydrogen) to thereaction zone as treat gas and quench gas.

In the system 1100, the vacuum residue treatment is catalytichydroprocessing. The vacuum residue stream 1142 is optionally processedin a vacuum residue hydrocracking zone 1180, in the presence of aneffective amount of hydrogen obtained from recycle within the vacuumresidue hydrocracking zone and from make-up hydrogen. In certainembodiments, all or a portion of the make-up hydrogen is derived fromthe steam cracker hydrogen stream 1232 from the olefins recovery train1230.

The vacuum residue hydrocracking zone 1180 operates under severehydrocracking conditions, and generally produces off-gas and light ends(not shown), pitch 1190, and one or more of a wild naphtha stream 1184,a diesel fraction 1186, an unconverted oil fraction 1188, and a middledistillates stream 1182 that is routed to the vacuum gas oilhydroprocessing zone 1160/170 and/or the diesel hydrotreating zone 1150.Effluent off-gases are recovered from the vacuum residue hydrocrackingzone 1180 and are passed to the olefins recovery train, the saturatedgas plant as part of the other gases stream 1134, and/or directly to afuel gas system. LPG can be recovered from the vacuum residuehydrocracking zone 1180 and routed to the steam cracking zone, theolefins recovery train and/or the saturated gas plant. In embodiments inwhich a naphtha fraction 114 is recovered, it is routed to the steamcracking zone 1220. In certain embodiments, in which a naphtha fraction1184 is recovered, it is routed through the crude complex 1105, alone,or in combination with other wild naphtha fractions from within theintegrated process. The unconverted oil fraction 118 is routed to thecoking zone 1300 as described herein.

The diesel fraction 1186 is recovered as a diesel fuel pool component,or used as diesel fuel compliant with Euro V standards. In embodimentsin which the vacuum residue hydrocracking zone 1180 operates underconditions effective to produce diesel fuel compliant with Euro Vstandards, the fraction 1186 can be combined with the diesel fuelfraction 1154 from the diesel hydrotreater 1150, the diesel fuelfraction 1164 from the vacuum gas oil hydrocracking zone 1160, or boththe diesel fuel fractions 1154 and 1164.

The vacuum residue hydrocracking zone 1180 can operate under severeconditions, depending on factors including the feedstock and the desireddegree of conversion. Such conditions are effective for removal of asignificant amount of the sulfur and other known contaminants, and forconversion of the vacuum residue 1142 feed into a major proportion ofhydrocracked products and unconverted oil 1188, and a minor portion ofoff-gases, light ends and pitch 1190 that is passed to the fuel oilpool. The hydrocracked products are recovered as a diesel fuel poolcomponent or used as diesel fuel compliant with Euro V standards, routedto the steam cracking zone 1220, and/or routed to one or more of theother hydroprocessing zones in the integrated process and system (thevacuum gas oil hydroprocessing zone 1160/1170 and/or the dieselhydrotreating zone 1150). The unconverted oil 1188 is routed to thecoking zone 1300 as described herein.

The vacuum residue hydrocracking zone 1180 can include one or moreebullated-beds, slurry-beds, fixed-beds or moving beds, in series and/orparallel arrangement. Additional equipment, including exchangers,furnaces, feed pumps, quench pumps, and compressors to feed thereactor(s) and maintain proper operating conditions, are well known andare considered part of the vacuum residue hydrocracking zone 1180. Inaddition, equipment including pumps, compressors, high temperatureseparation vessels, low temperature separation vessels and the like toseparate reaction products and provide hydrogen recycle within thevacuum residue hydrocracking zone 1180 are well known and are consideredpart of the vacuum residue hydrocracking zone 1180.

Furthermore, the vacuum residue hydrocracking zone 1180 can include ahydrotreating reaction zone and a hydrocracking reaction zone. Forexample, the vacuum residue 1142 from the vacuum distillation unit 1140can be routed to a hydrotreating reaction zone for initial removal ofheteroatom-containing compounds, such as those containing metals (inparticular Ni and vanadium), sulfur and nitrogen. In certainembodiments, the Ni+V content is reduced by at least about 30, 45, 77,95 or 100 wt %, the sulfur content is reduced by at least about 70, 80,92 or 100 wt %, and the nitrogen content is reduced by at least about70, 80, 92 or 100 wt %.

A vacuum residue hydrocracking zone 1180 generally includes a reactionzone and a fractionating zone. The reaction zone generally includes oneor more inlets in fluid communication with a source of the initialfeedstock 1142 and a source of hydrogen gas. One or more outlets of thereaction zone that discharge an effluent stream is in fluidcommunication with one or more inlets of the fractionating zone(typically including one or more high pressure and/or low pressureseparation stages therebetween for recovery of recycle hydrogen, notshown, and typically including a vacuum distillation unit). Thefractionating zone, which can include one or more flash and/ordistillation vessels, generally includes one or more outlets fordischarging gases, typically H₂, H₂S, NH₃, and light hydrocarbons(C1-C4); one or more outlets for discharging a wild naphtha stream 1184that is routed to the steam cracking zone 1220, one or more outlets fordischarging either or both of (a) a diesel fraction 1186 that isrecovered as a diesel fuel pool component, or used as diesel fuelcompliant with Euro V standards, and/or (b) a middle distillates stream1182 that is routed to the vacuum gas oil hydroprocessing zone 1160/170and/or the diesel hydrotreating zone 1150; and one or more outlets forrouting heavy oils 1188 typically including unconverted oils and otherhydrocarbons boiling above the atmospheric gas oil range (for instanceabout 370° C.), sometimes referred to as residue hydroprocessing VGO,all or a portion of which can be passed to the coking zone 1300 asdescribed herein; and one or more outlets for discharging pitch 1190,sometimes referred to as unconverted vacuum residue.

In operation of the vacuum residue hydrocracking zone 1180, a feedstockstream 1142 and hydrogen are introduced into one or more reactors. Thequantity of hydrogen is effective to support the requisite degree ofhydrocracking, feed type, and other factors, and can be any combinationincluding, recycle hydrogen from optional gas separation subsystemsassociated with the vacuum residue reaction zone, derived from vacuumresidue fractionator gas stream, and/or make-up hydrogen, if necessary.In certain embodiments, a reaction zone can contain multiple catalystbeds and can receive one or more quench hydrogen streams between thebeds (not shown). The reaction effluent stream contains converted,partially converted and unconverted hydrocarbons, and is passed to thefractionating zone (optionally after one or more high pressure and lowpressure separation stages to recover recycle hydrogen), generally torecover gas and liquid products and by-products, including one or moreof a wild naphtha stream 1184, a diesel fraction 1186, and a middledistillates stream 1182 (that is routed to the vacuum gas oilhydroprocessing zone 1160/170 and/or the diesel hydrotreating zone1150). A heavy oil stream 1188 is routed to the coking zone 1300 asdescribed herein and pitch 1190 is also recovered. The gas stream,typically containing H₂, H₂S, NH₃, and light hydrocarbons (C₁-C₄), isdischarged and recovered and can be further processed. Effluentoff-gases are passed to the olefins recovery train, the saturated gasplant as part of the other gases stream 1134, and/or directly to a fuelgas system. LPG can be recovered and routed to the steam cracking zone,the olefins recovery train and/or the saturated gas plant.

In certain embodiments, a vacuum residue hydrocracking zone 1180, caninclude an initial vacuum residue hydrotreating zone, generally having avacuum residue hydrotreating reaction zone, and the vacuum residuehydrocracking reaction zone and the fractionating zone as describedabove. The vacuum residue hydrotreating zone generally includes one ormore inlets in fluid communication with a source of the initialfeedstock 1142 and a source of hydrogen gas (including recycle andmake-up hydrogen). One or more outlets of the hydrotreating reactionzone that discharge hydrotreated effluent stream is in fluidcommunication with one or more inlets of the hydrocracking reactionzone. In certain embodiments, the hydrotreated effluents are passed tothe second reaction zone without separation of any excess hydrogen andlight gases. In optional embodiments, one or more high pressure and lowpressure separation stages are provided between the hydrotreating andhydrocracking reaction zones for recovery of recycle hydrogen (notshown). The hydrocracking reaction zone and the fractionation zonegenerally function as described above.

The feedstock stream 1142 and a hydrogen stream are charged to thehydrotreating reaction zone. The hydrogen stream contains an effectivequantity of hydrogen to support the requisite degree of hydrotreating,feed type, and other factors, and can be any combination including,recycle hydrogen from optional gas separation subsystems (not shown)associated with hydrotreating reaction zone and hydrocracking reactionzone, and/or derived from the vacuum residue fractionator gas stream,and make-up hydrogen if necessary. In certain embodiments, a reactionzone can contain multiple catalyst beds and can receive one or morequench hydrogen streams between the beds (not shown).

The hydrotreating reaction zone operates under effective conditions forproduction of hydrotreated effluent stream which is passed to thehydrocracking reaction zone (optionally after one or more high pressureand low pressure separation stages to recover recycle hydrogen),optionally along with a make-up hydrogen stream. The hydrotreatingreaction zone for treatment of the vacuum residue 1142, prior to residuehydrocracking, can contain one or more fixed-bed, ebullated-bed,slurry-bed, moving bed, continuous stirred tank (CSTR) or tubularreactors, in series and/or parallel arrangement, and is operated underconditions effective for vacuum residue hydrocracking, the particulartype of reactor, the feed characteristics, the desired product slate andthe catalyst selection. In certain embodiments, the operating conditionsfor hydrotreatment of the vacuum residue 1142, prior to residuehydrocracking, include:

a reactor temperature (° C.) in the range of from about 370-450,370-440, 370-430, 380-450, 380-440, 380-430, 390-450, 390-440 or390-430;

a hydrogen partial pressure (barg) in the range of from about 80-250,80-200, 80-150, 90-250, 90-200, 90-150, 100-250, 100-200 or 100-150;

a hydrogen gas feed rate (standard liters per liter of hydrocarbon feed,SLt/Lt) of up to about 3500, 3000 or 2500, in certain embodiments fromabout 1000-3500, 1000-3000, 1000-2500, 1500-3500, 1500-3000, 1500-2500,2000-3500, 2000-3000 or 2000-2500; and

a liquid hourly space velocity (h⁻¹), on a fresh feed basis relative tothe hydrotreating catalysts, in the range of from about 0.1-4.0,0.1-2.0, 0.1-1.5, 0.1-1.0, 0.2-4.0, 0.2-2.0, 0.2-1.5, 0.2-1.0, 0.5-4.0,0.5-2.0, 0.5-1.5 or 0.5-2.0.

An effective quantity of catalyst is provided for hydrotreatment of thevacuum residue 1142, prior to residue hydrocracking, including thosepossessing hydrotreating functionality, for hydrodemetallization,hydrodesulfurization and hydrodenitrification. Such catalysts generallycontain one or more active metal component of metals or metal compounds(oxides or sulfides) selected from the Periodic Table of the ElementsIUPAC Groups 6, 7, 8, 9 and 10. In certain embodiments, the active metalcomponent is one or more of Co, Ni, W and Mo. The active metal componentis typically deposited or otherwise incorporated on a support, such asamorphous alumina, amorphous silica alumina, zeolites, or combinationsthereof. In certain embodiments, the catalyst used for hydrotreatment ofthe vacuum residue 1142, prior to residue hydrocracking, includes one ormore beds selected from Co/Mo, Ni/Mo, Ni/W, and Co/Ni/Mo. Combinationsof one or more beds of Co/Mo, Ni/Mo, Ni/W and Co/Ni/Mo can also be used.The combinations can be composed of different particles containing asingle active metal species, or particles containing multiple activespecies. In certain embodiments, a combination of Co/Mo catalyst andNi/Mo catalyst are effective for hydrodemetallization,hydrodesulfurization and hydrodenitrification. One or more series ofreactors can be provided, with different catalysts in the differentreactors of each series.

For example, in one embodiment a vacuum residue hydrocracking reactor isan ebullated bed reactor. In the ebullated bed reactor liquid isrecycled internally with a recycle downflow conduit. A reaction zoneincludes an ebullated-bed reactor and an associated ebullating pump. Anebullated-bed reactor includes an inlet for receiving a mixture ofhydrogen gas and feedstock, and an outlet for discharging producteffluent. The ebullating pump is in fluid communication with theebullated-bed reactor and includes an inlet for receiving effluentrecycled from the ebullated-bed reactor and an outlet for dischargingthe recycled effluent at an increased pressure. In the reaction zone, amixture of hydrogen gas and feedstock is introduced into theebullated-bed reactor for reaction that includes conversion of thefeedstock into lower molecular weight hydrocarbons. Liquid reactioneffluent continuously flows down in the downflow conduit located insideebullated-bed reactor, and is recycled back to the ebullated-bed reactorat elevated pressure using the ebullating pump. Product effluent isrecovered via a reactor outlet. Alternatively, the recycle liquid can beobtained from a vapor separator located downstream of the reactor orobtained from an atmospheric stripper bottoms stream. The recycling ofliquid serves to ebullate and stabilize the catalyst bed, and maintaintemperature uniformity through the reactor.

In embodiments with an ebullated bed reactor for hydrocracking in thevacuum residue hydrocracking zone 1180, the catalyst is in an ebullated,or suspended state with random movement throughout the reactor vessel. Arecirculating pump expands the catalytic bed and maintains the catalystin suspension. The fluidized nature of the catalyst also permits on-linecatalyst replacement of a small portion of the bed to produce a high netbed activity that remains relatively constant over time. In an ebullatedbed reactor, highly contaminated feeds can be treated because of thecontinuous replacement of catalyst.

In certain embodiments, the vacuum residue hydrocracking zone 1180includes a hydrocracking ebullated bed reactor operating under thefollowing conditions:

a reactor temperature (° C.) in the range of from about 370-450,370-440, 370-430, 380-450, 380-440, 380-430, 390-450, 390-440 or390-430;

a hydrogen partial pressure (barg) in the range of from about 80-250,80-200, 80-150, 90-250, 90-200, 90-150, 100-250, 100-200 or 100-150;

a hydrogen gas feed rate (standard liters per liter of hydrocarbon feed,SLt/Lt) of up to about 3500, 3000 or 2500, in certain embodiments fromabout 1000-3500, 1000-3000, 1000-2500, 1500-3500, 1500-3000, 1500-2500,2000-3500, 2000-3000 or 2000-2500;

a liquid hourly space velocity (h⁻¹), on a fresh feed basis relative tothe hydrotreating catalysts, in the range of from about 0.1-4.0,0.1-2.0, 0.1-1.5, 0.1-1.0, 0.2-4.0, 0.2-2.0, 0.2-1.5, 0.2-1.0, 0.5-4.0,0.5-2.0, 0.5-1.5 or 0.5-2.0; and

annualized relative catalyst consumption (RCC) rate in the range ofabout 1.0-3.0, 1.0-2.2, 1.0-2.0, 1.0-1.8, 1.0-1.4, 1.2-3.0, 1.2-2.2,1.2-1.4, 1.4-3.0, 1.4-2.2, 1.4-1.8, 1.4-1.6, 1.6-1.8, 1.8-2.0, or2.0-2.2.

Effective hydrocracking catalyst for an ebullated bed reactor in thevacuum residue hydrocracking zone 1180 include those possessinghydrotreating functionality. Such catalysts generally contain one ormore active metal component of metals or metal compounds (oxides orsulfides) selected from the Periodic Table of the Elements IUPAC Groups6, 7, 8, 9 and 10. In certain embodiments, the active metal component isone or more of Co, Ni, and Mo. The active metal component is typicallydeposited or otherwise incorporated on a support, such as amorphousalumina, amorphous silica alumina, zeolites, or combinations thereof.One or more series of reactors can be provided, with different catalystsin the different reactors of each series.

Under the above conditions and catalyst selections, exemplary productsfrom a ebullated bed reactor in the vacuum residue hydrocracking zone1180 include LPG in the range of 3-6 wt %, diesel in the range of about25-40 wt %, naphtha in the range of about 10-20 wt %, pitch in the rangeof about 10-20 wt %, and hydroprocessed gas oil in the range of about20-30 wt %. All or a portion of diesel from the vacuum residuehydrocracking zone 1180 can be combined with the VGO and routed to thegas oil hydrocracking zone 1160, or routed to the diesel hydrotreatingzone 1150.

In embodiments with a slurry bed reactor for hydrocracking in the vacuumresidue hydrocracking zone 1180, the catalyst particles have a verysmall average dimension that can be uniformly dispersed and maintainedin the medium in order for efficient and immediate hydrogenationprocesses throughout the volume of the reactor. In general, in a slurrybed reactor, the catalyst is suspended in a liquid through which a gasis bubbled. The mechanism in a slurry bed reactor is a thermal crackingprocess and is based on free radical formation. The free radicals formedare stabilized with hydrogen in the presence of catalysts, therebypreventing the coke formation.

In certain embodiments, the vacuum residue hydrocracking zone 1180includes a hydrocracking slurry bed reactor operating under thefollowing conditions:

a reactor temperature (° C.) in the range of from about 370-450,370-440, 370-430, 380-450, 380-440, 380-430, 390-450, 390-440 or390-430;

a hydrogen partial pressure (barg) in the range of from about 80-250,80-200, 80-150, 90-250, 90-200, 90-150, 100-250, 100-200 or 100-150;

a hydrogen gas feed rate (standard liters per liter of hydrocarbon feed,SLt/Lt) of up to about 3500, 3000 or 2500, in certain embodiments fromabout 1000-3500, 1000-3000, 1000-2500, 1500-3500, 1500-3000, 1500-2500,2000-3500, 2000-3000 or 2000-2500;

a liquid hourly space velocity (h⁻¹), on a fresh feed basis relative tothe hydrotreating catalysts, in the range of from about 0.1-4.0,0.1-2.0, 0.1-1.5, 0.1-1.0, 0.2-4.0, 0.2-2.0, 0.2-1.5, 0.2-1.0, 0.5-4.0,0.5-2.0, 0.5-1.5 or 0.5-2.0; and

annualized relative catalyst consumption (RCC) rate in the range ofabout 1.0-3.0, 1.0-2.2, 1.0-2.0, 1.0-1.8, 1.0-1.4, 1.2-3.0, 1.2-2.2,1.2-1.4, 1.4-3.0, 1.4-2.2, 1.4-1.8, 1.4-1.6, 1.6-1.8, 1.8-2.0, or2.0-2.2.

Effective hydrocracking catalyst for a slurry bed reactor in the vacuumresidue hydrocracking zone 1180 include those possessing hydrotreatingand hydrogenation functionality. Such catalysts generally contain one ormore active transition metal component of metals or metal compounds(oxides or sulfides) selected from the Periodic Table of the ElementsIUPAC Groups 6, 7, 8, 9 and 10. The active metal component is typicallyunsupported. The catalyst is generally in the form of a sulfide of themetal that is formed during the reaction or in a pretreatment step. Themetals that make up the dispersed catalysts can be selected from Mo, W,Ni, Co and/or Ru. Mo and W are especially preferred since theirperformance is superior to vanadium or iron, which in turn are preferredover Ni, Co or Ru. The active metal component is typically deposited orotherwise incorporated on a support, such as amorphous alumina,amorphous silica alumina, zeolites, or combinations thereof. Thecatalysts can be used at a low concentration, for example, a few hundredparts per million (ppm), in a once-through arrangement, but are notespecially effective in upgrading of the heavier products under thoseconditions. To obtain better product quality, catalysts are used athigher concentration, and it is necessary to recycle the catalyst inorder to make the process economically feasible. The catalysts can berecovered using methods such as settling, centrifugation or filtration.One or more series of reactors can be provided, with different catalystsin the different reactors of each series.

Under the above conditions and catalyst selections, exemplary productsfrom a slurry bed reactor in the vacuum residue hydrocracking zone 1180include LPG in the range of 3-6 wt %, diesel in the range of about 23-55wt %, naphtha in the range of about 10-20 wt %, pitch in the range ofabout 10-20 wt %, and hydroprocessed gas oil in the range of about 15-30wt %. All or a portion of diesel from the vacuum residue hydrocrackingzone 1180 can be combined with the VGO and routed to the gas oilhydrocracking zone 1160, or routed to the diesel hydrotreating zone1150.

In embodiments with a fixed bed reactor for hydrocracking in the vacuumresidue hydrocracking zone 1180, catalyst particles are stationary anddo not move with respect to a fixed reference frame. In conventionalfixed-bed reactors, the hydroprocessing catalysts are replaced regularlyin order to maintain the desired level of catalyst activity andthroughput.

In certain embodiments, the vacuum residue hydrocracking zone 1180includes a hydrocracking fixed bed reactor operating under the followingconditions:

a reactor temperature (° C.) in the range of from about 370-470,370-450, 380-470, 380-450, 390-470 or 390-450;

a hydrogen partial pressure (barg) in the range of from about 80-250,80-200, 80-150, 90-250, 90-200, 90-150, 100-250, 100-200 or 100-150;

a hydrogen gas feed rate (standard liters per liter of hydrocarbon feed,SLt/Lt) of up to about 3500, 3000 or 2500, in certain embodiments fromabout 1000-3500, 1000-3000, 1000-2500, 1500-3500, 1500-3000, 1500-2500,2000-3500, 2000-3000 or 2000-2500; and

a liquid hourly space velocity (h⁻¹), on a fresh feed basis relative tothe hydrotreating catalysts, in the range of from about 0.1-4.0,0.1-2.0, 0.1-1.5, 0.1-1.0, 0.2-4.0, 0.2-2.0, 0.2-1.5, 0.2-1.0, 0.5-4.0,0.5-2.0, 0.5-1.5 or 0.5-2.0.

Effective hydrocracking catalyst for a fixed bed reactor in the vacuumresidue hydrocracking zone 1180 include those possessing hydrotreatingfunctionality. Such catalysts generally contain one or more active metalcomponent of metals or metal compounds (oxides or sulfides) selectedfrom the Periodic Table of the Elements IUPAC Groups 6, 7, 8, 9 and 10.In certain embodiments, the active metal component is one or more of Co,Ni, and Mo. The active metal component is typically deposited orotherwise incorporated on a support, such as amorphous alumina,amorphous silica alumina, zeolites, or combinations thereof. One or moreseries of reactors can be provided, with different catalysts in thedifferent reactors of each series. Effective liquid hourly spacevelocity values (h⁻¹), on a fresh feed basis relative to thehydrotreating catalysts, are in the range of from about 0.1-0.5,0.1-0.2, 0.2-0.3, 0.3-0.4, 0.4-0.5, 0.1-0.3 or 0.3-0.5.

In embodiments with a moving bed reactor for hydrocracking in the vacuumresidue hydrocracking zone 1180, catalyst can be replaced withoutinterrupting the unit's operation. Moving bed reactors combine certainadvantages of fixed bed operations and the relatively easy catalystreplacement of ebullated bed technology. During catalyst replacement,catalyst movement is slow compared to the linear velocity of the feed.The frequency of catalyst replacement depends on the rate of catalystdeactivation. Catalyst addition and withdrawal are performed, forinstance, via a sluice system at the top and bottom of the reactor. Incertain embodiments, the moving bed reactor is operated in a countercurrent mode. In the counter current mode, spent catalyst alreadysaturated by contaminates is located at the bottom of the reactor andmeets the fresh feed entering from the bottom. This allows for freshcatalyst located at the top of the reactor to react with an alreadydemetallized feed.

In certain embodiments, the vacuum residue hydrocracking zone 1180includes a hydrocracking moving bed reactor operating under theconditions stated above for a fixed bed reactor. Catalyst material in amoving bed reactor is continuously replaced in an annualized relativecatalyst consumption (RCC) rate in the range of about 0.4-0.8, 0.4-0.6,0.6-0.8, 0.4-0.5, 0.5-0.6, 0.6-0.7 and 0.7-0.8. Under the aboveconditions and catalyst selections, exemplary products from a fixed bedreactor or moving bed reactor in the vacuum residue hydrocracking zone1180 include LPG in the range of 3-6 wt %, diesel in the range of about5-30 wt %, naphtha in the range of about 1-20 wt %, pitch in the rangeof about 30-60 wt %, and hydroprocessed gas oil in the range of about20-40 wt %. All or a portion of diesel from the vacuum residuehydrocracking zone 1180 can be combined with the VGO and routed to thegas oil hydrocracking zone 1160, or routed to the diesel hydrotreatingzone 1150.

In the description herein, both the steam cracking zone 1220 and theproduct separation systems associated therewith are collectivelyreferred to as the “steam cracker complex” 1215 in certain instances,although a person having ordinary skill in the art will appreciate thatthe steam cracking zone can contain different furnaces and associatedexchangers, with certain products from each combined for furtherdownstream operations.

The steam cracking zone 1220, which operates as high severity or lowseverity thermal cracking process, generally converts LPG, naphtha andheavier hydrocarbons primarily into a mixed product stream containingmixed C1-C4 paraffins and olefins. In certain embodiments, the steamcracking zone 1220 processes straight-run liquids from the crude unit,ethane and/or propane (from outside battery limits and/or recycled) andvarious recycle streams from chemical production and recovery areaswithin the integrated process and system.

For instance, the plural feeds to the steam cracking zone 1220 include:light ends 1136 and naphtha 1114 from the crude complex 1105; a recycleethane stream 1236 from the olefins recovery zone 1230; a recyclepropane stream 1246 from a methylacetylene/propadiene (MAPD) saturationand propylene recovery zone 1244 described below; C4 raffinate 1264 froma 1-butene recovery zone 1266 described below; wild naphtha 1152 from adiesel hydrotreating zone 1150 described above; wild naphtha 1162 from agas oil hydrocracking zone 1160, or wild naphtha 1172 from a gas oilhydrotreating zone 1170, described above; and a naphtha fraction 1184from the vacuum residue hydrocracking zone 1180. The products from thesteam cracking zone 1220 include: a quenched cracked gas streamcontaining mixed C1-C4 paraffins and olefins that is routed to theolefins recovery zone 1230; a pyrolysis gasoline stream 1228 that istreated separately; and a pyrolysis fuel oil stream 1226 that is treatedseparately.

The steam cracking zone 1220 operates under parameters effective tocrack the feed into desired products including ethylene, propylene,butadiene, and mixed butenes. Pyrolysis gasoline and pyrolysis oil arealso recovered. In certain embodiments, the steam cracking furnace(s)are operated at conditions effective to produce an effluent having apropylene-to-ethylene weight ratio of from about 0.3-0.8, 0.3-0.6,0.4-0.8 or 0.4-0.6. The steam cracking zone 1220 generally comprises oneor more trains of furnaces. For instance, a typical arrangement includesreactors that can operate based on well-known steam pyrolysis methods,that is, charging the thermal cracking feed to a convection section inthe presence of steam to raise the temperature of the feedstock, andpassing the heated feed to the pyrolysis reactor containing furnacetubes for cracking. In the convection section, the mixture is heated toa predetermined temperature, for example, using one or more waste heatstreams or other suitable heating arrangement(s).

The feed mixture is heated to a high temperature in a convection sectionand material with a boiling point below a predetermined temperature isvaporized. The heated mixture (in certain embodiments along withadditional steam) is passed to the pyrolysis section operating at afurther elevated temperature for short residence times, such as 1-2seconds or less, effectuating pyrolysis to produce a mixed productstream. In certain embodiments separate convection and radiant sectionsare used for different incoming feeds to the steam cracking zone 1220with conditions in each optimized for the particular feed.

In certain embodiments, steam cracking in the steam cracking zone 1220is carried out using the following conditions: a temperature (° C.) inthe convection section in the range of about 400-600, 400-550, 450-600or 500-600; a pressure (barg) in the convection section in the range ofabout 4.3-4.8, 4.3-4.45, 4.3-4.6, 4.45-4.8, 4.45-4.6 or 4.6-4.8; atemperature (° C.) in the pyrolysis section in the range of about700-950, 700-900, 700-850, 750-950, 750-900 or 750-850; a pressure(barg) in the pyrolysis section in the range of about 1-4, 1-2 or 1-1.4;a steam-to-hydrocarbon ratio in the convection section in the range ofabout 0.3:1-2:1, 0.3:1-1.5:1, 0.5:1-2:1, 0.5:1-1.5:1, 0.7:1-2:1,0.7:1-1.5:1, 1:1-2:1 or 1:1-1.5:1; and a residence time (seconds) in thepyrolysis section in the range of about 0.05-1.2, 0.05-1, 0.1-1.2,0.1-1, 0.2-1.2, 0.2-1, 0.5-1.2 or 0.5-1.

In operation of the steam cracking zone 1220, effluent from the crackingfurnaces is quenched, for instance, using transfer line exchangers, andpassed to a quench tower. The light products, quenched cracked gasstream are routed to the olefins recovery zone 1230. Heavier productsare separated in a hot distillation section. A raw pyrolysis gasolinestream 1228 is recovered in the quench system. Pyrolysis oil 1226 isseparated at a primary fractionator tower before the quench tower.

In operation of one embodiment of the steam cracking zone 1220, thefeedstocks are mixed with dilution steam to reduce hydrocarbon partialpressure and then are preheated. The preheated feeds are fed to tubularreactors mounted in the radiant sections of the cracking furnaces. Thehydrocarbons undergo free-radical pyrolysis reactions to form lightolefins ethylene and propylene, and other by-products. In certainembodiments, dedicated cracking furnaces are provided with cracking tubegeometries optimized for each of the main feedstock types, includingethane, propane, and butanes/naphtha. Less valuable hydrocarbons, suchas ethane, propane, C4 raffinate, and aromatics raffinate, producedwithin the integrated system and process, are recycled to extinction inthe steam cracking zone 1220.

In certain embodiments, cracked gas from the furnaces is cooled intransfer line exchangers (quench coolers), for example, producing 1800psig steam suitable as dilution steam. Quenched cracked gas enters aprimary fractionator within the steam cracking complex 1215 for removalof pyrolysis fuel oil bottoms from lighter components. The primaryfractionator enables efficient recovery of pyrolysis fuel oil. Pyrolysisfuel oil is stripped with steam in a fuel oil stripper to controlproduct vapor pressure, and cooled. In addition, secondary quench can becarried out by direct injection of pyrolysis fuel oil as quench oil intoliquid furnace effluents. The stripped and cooled pyrolysis fuel oil canbe sent to a fuel oil pool or product storage. The primary fractionatoroverhead is sent to a quench water tower; condensed dilution steam forprocess water treating, and raw pyrolysis gasoline, are recovered.Quench water tower overhead is sent to the olefins recovery zone 1230,particularly the first compression stage. Raw pyrolysis gasoline is sentto a gasoline stabilizer to remove any light ends and to control vaporpressure in downstream pyrolysis gasoline processing. A closed-loopdilution steam/process water system is enabled, in which dilution steamis generated using heat recovery from the primary fractionator quenchpumparound loops. The primary fractionator enables efficient recovery ofpyrolysis fuel oil due to energy integration and pyrolysis fuel oilcontent in the light fraction stream.

The mixed product stream 1224 effluent from the steam cracking zone 1220is routed to the olefins recovery zone 1230. For instance, lightproducts from the quenching step, C4-, H₂ and H₂S, are contained in themixed product stream that is routed to the olefins recovery zone 1230.Products include: hydrogen 1232 that is used for recycle and/or passedto users; fuel gas 1234 that is passed to a fuel gas system; ethane thatis recycled to the steam cracking zone 1220; ethylene 1236 that isrecovered as product; a mixed C3 stream 1238 that is passed to a methylacetylene/propadiene saturation and propylene recovery zone 1244; and amixed C4 stream 1240 that is passed to a butadiene extraction zone 1250.

The olefins recovery zone 1230 operates to produce on-specificationlight olefin (ethylene and propylene) products from the mixed productstream. For instance, cooled gas intermediate products from the steamcracker is fed to a cracked gas compressor, caustic wash zone, and oneor more separation trains for separating products by distillation. Incertain embodiments two trains are provided. The distillation trainincludes a cold distillation section, wherein lighter products such asmethane, hydrogen, ethylene, and ethane are separated in a cryogenicdistillation/separation operation. The mixed C2 stream from the steamcracker contains acetylenes that are hydrogenated to produce ethylene inan acetylene selective hydrogenation unit. This system can also includeethylene, propane and/or propylene refrigeration facilities to enablecryogenic distillation.

In one embodiment, mixed product stream 1224 from the steam crackingzone 1220 is passed through three to five stages of compression. Acidgases are removed with caustic in a caustic wash tower. After anadditional stage of compression and drying, light cracked gases arechilled and routed to a depropanizer. In certain embodiments lightcracked gases are chilled with a cascaded two-level refrigeration system(propylene, mixed binary refrigerant) for cryogenic separation. Afront-end depropanizer optimizes the chilling train and demethanizerloading. The depropanizer separates C3 and lighter cracked gases as anoverhead stream, with C4s and heavier hydrocarbons as the bottomsstream. The depropanizer bottoms are routed to the debutanizer, whichrecovers a crude C4s stream 1240 and any trace pyrolysis gasoline.

The depropanizer overhead passes through a series of acetyleneconversion reactors, and is then fed to the demethanizer chilling train,which separates a hydrogen-rich product via a hydrogen purificationsystem, such as pressure swing adsorption. Front-end acetylenehydrogenation is implemented to optimize temperature control, minimizegreen oil formation and simplify ethylene product recovery byeliminating a C2 splitter pasteurization section that is otherwisetypically included in product recovery. In addition, hydrogenpurification via pressure swing adsorption eliminates the need for amethanation reactor that is otherwise typically included in productrecovery.

The demethanizer recovers methane in the overhead for fuel gas, and C2and heavier gases in the demethanizer bottoms are routed to thedeethanizer. The deethanizer separates ethane and ethylene overheadwhich feeds a C2 splitter. The C2 splitter recovers ethylene product1236, in certain embodiments polymer-grade ethylene product, in theoverhead. Ethane 1242 from the C2 splitter bottoms is recycled to thesteam cracking zone 1220. Deethanizer bottoms contain C3s from whichpropylene product 1248, in certain embodiments polymer-grade propyleneproduct, is recovered as the overhead of a C3 splitter, with propane1246 from the C3 splitter bottoms recycled to the steam cracking zone1220.

A methyl acetylene/propadiene (MAPD) saturation and propylene recoveryzone 1244 is provided for selective hydrogenation to convert methylacetylene/propadiene, and to recover propylene from a mixed C3 stream1238 from the olefins recovery zone 1230. The mixed C3 1238 from theolefins recovery zone 1230 contains a sizeable quantity of propadieneand propylene. The methyl acetylene/propadiene saturation and propylenerecovery zone 1244 enables production of propylene 1248, which can bepolymer-grade propylene in certain embodiments.

The methyl acetylene/propadiene saturation and propylene recovery zone1244 receives hydrogen and mixed C3 1238 from the olefins recovery zone1230. Products from the methyl acetylene/propadiene saturation andpropylene recovery zone 1244 are propylene 1248 which is recovered, andthe recycle C3 stream 1246 that is routed to the steam cracking zone1220. In certain embodiments, hydrogen used to saturate methyl acetyleneand propadiene is derived from hydrogen 1232 obtained from the olefinsrecovery zone 1230.

A stream 1240 containing a mixture of C4s, known as crude C4s, from theolefins recovery zone 1230, is routed to a butadiene extraction zone1250 to recover a high purity 1,3-butadiene product 1252 from the mixedcrude C4s. In certain embodiments (not shown), a step of hydrogenationof the mixed C4 before the butadiene extraction zone 1250 can beintegrated to remove acetylenic compounds, for instance, with a suitablecatalytic hydrogenation process using a fixed bed reactor. 1,3-butadiene1252 is recovered from the hydrogenated mixed C4 stream by extractivedistillation using, for instance, n-methyl-pyrrolidone (NMP) ordimethylformamide (DMF) as solvent. The butadiene extraction zone 1250also produces a raffinate stream 1254 containing butane/butene, which ispassed to a methyl tertiary butyl ether zone 1256.

In one embodiment, in operation of the butadiene extraction zone 1250,the stream 1240 is preheated and vaporized into a first extractivedistillation column, for instance having two sections. NMP or DMFsolvent separates the 1,3-butadiene from the other C4 componentscontained in stream 1254. Rich solvent is flashed with vapor to a secondextractive distillation column that produces a high purity 1,3-butadienestream as an overhead product. Liquid solvent from the flash and thesecond distillation column bottoms are routed to a primary solventrecovery column. Bottoms liquid is circulated back to the extractor andoverhead liquid is passed to a secondary solvent recovery or solventpolishing column. Vapor overhead from the recovery columns combines withrecycle butadiene product into the bottom of the extractor to increaseconcentration of 1,3-butadiene. The 1,3-butadiene product 1252 can bewater washed to remove any trace solvent. In certain embodiments, theproduct purity (wt %) is 97-99.8, 97.5-99.7 or 98-99.6 of 1,3-butadiene;and 94-99, 94.5-98.5 or 95-98 of the 1,3-butadiene content (wt %) of thefeed is recovered. In addition to the solvent such as DMF, additivechemicals are blended with the solvent to enhance butadiene recovery. Inaddition, the extractive distillation column and primary solventrecovery columns are reboiled using high pressure steam (for instance,600 psig) and circulating hot oil from another source as heat exchangefluid.

A methyl tertiary butyl ether zone 1256 is integrated to produce methyltertiary butyl ether 1262 and a second C4 raffinate 1260 from the firstC4 raffinate stream 1254. In certain embodiments C4 Raffinate 1 1254 issubjected to selective hydrogenation to selectively hydrogenate anyremaining dienes and prior to reacting isobutenes with methanol toproduce methyl tertiary butyl ether.

Purity specifications for recovery of a 1-butene product stream 1268necessitate that the level of isobutylene in the second C4 raffinate1260 be reduced. In general, the first C4 raffinate stream 1254containing mixed butanes and butenes, and including isobutylene, ispassed to the methyl tertiary butyl ether zone 1256. Methanol 1258 isalso added, which reacts with isobutylene and produces methyl tertiarybutyl ether 1262. For instance, methyl tertiary butyl ether product andmethanol are separated in a series of fractionators, and routed to asecond reaction stage. Methanol is removed with water wash and a finalfractionation stage. Recovered methanol is recycled to the fixed beddownflow dehydrogenation reactors. In certain embodiments, additionalisobutylene can be introduced to the methyl tertiary butyl ether zone1256, for instance, derived from a metathesis conversion unit.

In operation of one embodiment of the methyl tertiary butyl ether zone1256, the raffinate stream 1254, contains 35-45%, 37-42.5%, 38-41% or39-40% isobutylene by weight. This component is removed from the C4raffinate 1260 to attain requisite purity specifications, for instance,greater than or equal to 98 wt % for the 1-butene product stream 1268from the butene-1 recovery zone 1266. Methanol 1258, in certainembodiments high purity methanol having a purity level of greater thanor equal to 98 wt % from outside battery limits, and the isobutylenecontained in the raffinate stream 1254 and in certain embodimentsisobutylene from an optional metathesis step, react in a primaryreactor. In certain embodiments the primary reactor is a fixed beddownflow dehydrogenation reactor and operates for isobutylene conversionin the range of about 70-95%, 75-95%, 85-95% or 90-95% on a weightbasis. Effluent from the primary reactor is routed to a reaction columnwhere reactions are completed. In certain embodiments, exothermic heatof the reaction column and the primary reactor can optionally be used tosupplement the column reboiler along with provided steam. The reactioncolumn bottoms stream contains methyl tertiary butyl ether, traceamounts, for instance, less than 2%, of unreacted methanol, and heavyproducts produced in the primary reactor and reaction column. Reactioncolumn overhead contains unreacted methanol and non-reactive C4raffinate. This stream is water washed to remove unreacted methanol andis passed to the 1-butene recovery zone 1266 as the C4 raffinate 1260.Recovered methanol is removed from the wash water in a methanol recoverycolumn and recycled to the primary reactor.

The C4 raffinate stream 1260 from the methyl tertiary butyl ether zone1256 is passed to a separation zone 1266 for butene-1 recovery. Incertain embodiments, upstream of the methyl tertiary butyl ether zone1256, or between the methyl tertiary butyl ether zone 1256 andseparation zone 1266 for butene-1 recovery, a selective hydrogenationzone can also be included (not shown). For instance, in certainembodiments, raffinate from the methyl tertiary butyl ether zone 1256 isselectively hydrogenated in a selective hydrogenation unit to producebutene-1. Other co-monomers and paraffins are also co-produced. Theselective hydrogenation zone operates in the presence of an effectiveamount of hydrogen obtained from recycle within the selectivehydrogenation zone and make-up hydrogen; in certain embodiments, all ora portion of the make-up hydrogen for the selective hydrogenation zoneis derived from the steam cracker hydrogen stream 1232 from the olefinsrecovery train 1230.

For selective recovery of a 1-butene product stream 1268, and to recovera recycle stream 1264 that is routed to the steam cracking zone 1220,and/or in certain embodiments described herein routed to a metathesiszone, one or more separation steps are used. For example, 1-butene canbe recovered using two separation columns, where the first columnrecovers olefins from the paraffins and the second column separates1-butene from the mixture including 2-butene, which is blended with theparaffins from the first column and recycled to the steam cracker as arecycle stream 1264.

In certain embodiments, the C4 raffinate stream 1260 from the methyltertiary butyl ether zone 1256 is passed to a first splitter, from whichisobutane, 1-butene, and n-butane are separated from heavier C4components. Isobutane, 1-butene, and n-butane are recovered as overhead,condensed in an air cooler and sent to a second splitter. Bottoms fromthe first splitter, which contains primarily cis- and trans-2-butene canbe added to the recycle stream 1264, or in certain embodiments describedherein passed to a metathesis unit. In certain arrangements, the firstsplitter overhead enters the mid-point of the second splitter. Isobutaneproduct can optionally be recovered in an overhead stream, 1-buteneproduct 1268 is recovered as a sidecut, and n-butane is recovered as thebottoms stream. Bottoms from both splitters are recovered as all or aportion of recycle stream 1264.

A pyrolysis gasoline stream 1228 can be subjected to treatment to formgasoline blending components. Optionally a pyrolysis gasoline stream1228 can be subjected to hydrotreating and aromatics extraction forrecovery of aromatics, as disclosed in commonly owned US PatentPublication Numbers US20180142168A1, US20180223197A1 andUS20180155642A1, and US Patents U.S. Ser. No. 10/472,579B2, U.S. Ser.No. 10/472,580B2, U.S. Ser. No. 10/487,276B2, U.S. Ser. No.10/487,275B2, U.S. Ser. No. 10/407,630B2 and U.S. Ser. No. 10/472,574B2,which are incorporated by reference herein.

For example, as shown in dashed lines as optional, all, a substantialportion or a significant portion of the pyrolysis gasoline 1228 from thesteam cracker complex 1215 is fed to a py-gas hydrotreatment andrecovery center 1270/1272. In certain embodiments, select hydrocarbonshaving 5-12 carbons are recovered from untreated pyrolysis gasoline andthe remainder is subsequently hydrotreated for aromatics recovery. In apy-gas hydrotreating unit, diolefins and olefins in the pyrolysisgasoline are saturated. Hydrotreated pyrolysis gasoline from the py-gashydrotreating unit (in certain embodiments having C5s removed andrecycled to the steam cracking complex 1215 instead of or in conjunctionwith C5s from the aromatics extraction zone 1272) is routed to thearomatics extraction zone 1272. The py-gas hydrotreating zone 1270 andthe aromatics extraction zone 1272 are shown for simplicity in a singleschematic block in the figures herein.

The aromatics extraction zone 1272 includes, for instance, one or moreextractive distillation units, and operates to separate the hydrotreatedpyrolysis gasoline into an aromatics stream 1274 containing high-puritybenzene, toluene, xylenes and C9 aromatics, which are recovered forchemical markets. C5 raffinate 1282 and non-aromatics 1280 (forinstance, C6-C9) are recycled to the steam cracking complex 1215. Aheavy aromatics stream 1278 (for instance, C10-C12) can be used as anaromatic solvent, an octane boosting additive or as a cutter stock intoa fuel oil pool. In certain embodiments ethylbenzene 1276 can berecovered.

A pyrolysis fuel oil stream 1226 can be blended into the fuel oil poolas a low sulfur component, and/or used as carbon black feedstock. Incertain embodiments, all or a portion of the pyrolysis oil stream 1226can be fractioned into light pyrolysis oil and heavy pyrolysis oil. Forinstance, light pyrolysis oil can be blended with one or more of themiddle distillate streams, so that 0-100% of light pyrolysis oil derivedfrom the pyrolysis oil stream 1226 is processed to produce in the dieselhydrotreating zone 1150, and/or the vacuum gas oil hydroprocessing zone1160/1170. Heavy pyrolysis oil can be blended into the fuel oil pool asa low sulfur component, and/or used as a carbon black feedstock. Infurther embodiments, 0-100% of light pyrolysis oil and/or 0-100% ofheavy pyrolysis oil derived from the pyrolysis oil stream 1226 can beprocessed in the optional residue hydrocracking zone 1180. In certainembodiments, all, a substantial portion, a significant portion or amajor portion of light pyrolysis oil can be passed to the residuehydrocracking zone 1180; any remainder can be routed to the dieselhydrotreating zone 1150 and/or the vacuum gas oil hydroprocessing zoneand/or the fuel oil pool.

FIG. 2A schematically depicts an embodiment of a process and system 2100for conversion of crude oil to petrochemicals and fuel products,integrating deep hydrogenation of middle distillates to increase thesteam cracking feedstock, and accordingly increase production of steamcracking products including ethylene, propylene and other valuablepetrochemical products. The several unit operations and streams aredenoted as a “2000” series of reference numerals that are similar tothose described in conjunction with FIG. 1. Unless otherwise noted,units and streams with similar “1000” and “2000” series referencenumbers are similar or identical.

As described above in conjunction with the system 1100, the system 2100generally includes a crude complex 2105, typically including anatmospheric distillation zone (“ADU”) 2110, a saturated gas plant 2130,a vacuum distillation zone (“VDU”) 2140 and a coking zone 2300. Thedistillate products from the atmospheric distillation zone 2110 includestraight run naphtha 2114, one or more middle distillate streamsincluding light middle distillates 2116, medium range middle distillates2122, and heavier distillates 2124. Atmospheric residue 2126 can befurther separated in the vacuum distillation zone 2140 to obtain vacuumgas oil 2144 and vacuum residue 2142. In certain embodiments, a minorportion of the atmospheric residue fraction 2126, shown as portion 2302,can bypass the vacuum distillation zone 2140 and is routed to the cokingzone 2300. In certain embodiments, 0-100% of the atmospheric residuefraction 2126 can be used as portion 2302 to the coking zone 2300. Incertain embodiments, a minor portion of the vacuum residue stream 2142,shown as portion 2304, can be routed to the coking zone 2300. In certainembodiments, 0-100% of the vacuum residue fraction 2142 can be used asportion 2304 to the coking zone 2300.

The coking zone 2300 is operable to receive and convert all or a portionof the feed stream, which can be one or more of: all or a portion of theunconverted oil stream 2166 and/or the hydrotreated gas oil stream 2176;the unconverted oil stream 2188 in embodiments in which residuehydrocracking is integrated; atmospheric residue 2302; or vacuum residue2304. The coking zone 2300 can be operated to produce at least lightgases 2330, coker naphtha 2332, light coker gas oil 2334, heavy cokergas oil 2336, and coke 2338. The coking reaction zone 2300 includeassociated therewith a mixing zone, a separator and a catalyst-strippingzone.

Off-gases from the coking zone 2300 can be integrated with the fuel gassystem. In certain embodiments (not shown), certain gases, aftertreatment in an unsaturated gas plant, can be routed to the separationunits within the steam cracking complex 2215, and/or LPGs can be routedto the steam cracking zone 2220. All, a substantial portion, asignificant portion or a major portion of the gases containing lightolefins (a C2− stream and a C3+ stream) are routed through theunsaturated gas plant. The remainder, if any, can be routed to the steamcracking zone 2220 and/or the olefins recovery train 2230.

In the configuration of FIG. 2A, all or a portion of the coker naphtha2332 can be processed to produce additional feed for the steam crackingzone 2220. In certain embodiments, all or a portion of the coker naphtha2332, optionally after hydrogenation (under conditions and usingcatalysts described herein with respect to the naphtha hydrogenationzone 2204), can be processed as described below in a py-gashydrotreatment and recovery center 2270/2272 (as shown in dashed lines)to increase the quantity of raffinate as additional feed to the steamcracking zone 2220. In certain embodiments all or a portion of the cokernaphtha 2332 can be subjected to hydrogenation (under conditions andusing catalysts described herein with respect to the naphthahydrogenation zone 2204), and hydrogenated effluent used as additionalfeed to the steam cracking zone 2220. Any portion of the coker naphtha2332 that is not routed to the py-gas hydrotreatment and recovery center2270/2272, shown in dashed lines, can be hydrotreated and recovered forfuel production. For instance, in modalities in which the objective ismaximum petrochemical production, all, a substantial portion, asignificant portion or a major portion of the coker naphtha 2332 is usedfor additional steam cracking feed; the remainder, if any, is recoveredfor fuel production and incorporation into a gasoline pool.

In additional embodiments, all or a portion of the coker naphtha 2332 ishydrotreated and recovered for fuel production and incorporation into agasoline pool. Optionally, a portion of the coker naphtha 2332 that isnot recovered for fuel production can be processed in the py-gashydrotreatment and recovery center 2270/2272, as shown in dashed lines,to increase the quantity of raffinate as additional feed to the steamcracking zone 2220, or subjected to hydrogenation with hydrogenatedeffluent used as additional steam cracking feed.

Other products from the coking zone 2300 include cycle oil, light cokergas oil 2334 and heavy coker gas oil 2336. Heavy coker gas oil stream2336 can be routed to a fuel oil pool and/or used as feedstock forproduction of carbon black. In certain embodiments, all, a substantialportion, a significant portion or a major portion of the light coker gasoil 2334 is used as feed to the deep hydrogenation zone 2200, alone orin combination with other feeds as described herein. In certainembodiments, an additional hydrotreating reaction zone can be includedbetween the coking zone 2300 and the DHG zone 2200, depending on thesulfur and nitrogen content of the light coker gas oil 4334, and whetherthis stream is processed in the DHG zone 2200 alone or in combinationwith other middle distillate streams that have lower sulfur and nitrogencontent. In these embodiments, the catalyst(s), temperature and spacevelocity for hydrotreating can be similar to those of the dieselhydrotreating zone 1150 described herein, with a hydrogen partialpressure in the range of from about 50-120, 50-100, 50-90, 60-120,60-100, 60-90, 70-120, 70-100 or 70-90.

A steam cracking zone 2220 is integrated and receives at least a portionof the light coker gas oil produced within the system that are subjectedto deep hydrogenation. The steam cracking zone can include a single unitor multiple units, each processing feedstocks having different boilingpoint characteristics. In certain embodiments the steam cracking zone2220 receives plural naphtha streams including the straight run naphtha2114 and other naphtha fractions produced within the system, shown asthe combined stream 2222 in FIGS. 2A (dashed lines) and 2B, and also asdescribed herein with respect to the system 1100. In certainembodiments, one or more of the individual naphtha sources that make upthe combined stream 2222 are passed to the steam cracking zone 2220,while others are diverted for other purposes such as gasoline blendingcomponents after treatment (if necessary).

For the light middle distillates 2116, such as a kerosene fraction oralight kerosene fraction, a kerosene sweetening zone 2120 can optionallybe used to produce a light range middle distillate fraction 2118′ as asource of steam cracking feedstock. In certain embodiments the lightrange middle distillate fraction 2118′ is passed to the DHG zone 2200.In additional embodiments, the light range middle distillate fraction2118′ is divided by weight into a heavy portion passing and a lightportion, with the heavy portion passing to the DHG zone 2200 or the DHTzone 2150, and the light portion combined with naphtha as streamcracking feed. In additional embodiments, the light middle distillates2116 can be passed to the DHT zone 2150, or the components of the lightmiddle distillates 2116 can be combined and discharged with the mediumrange middle distillates 2122 (so that a light middle distillates 2116stream is not provided).

Medium range middle distillates 2122 are passed to a middle distillatehydrotreating zone 2150 to produce a hydrotreated naphtha fraction 2152as part of an optional naphtha feed to the steam cracking zone 2220, andall or a portion of a middle distillate fraction 2154′ can be used as afeed for hydrogenation. In certain embodiments, all or a portion of themiddle distillate fraction 2154′ can be recovered as a diesel fuelblending component that can be compliant with Euro V diesel standards asdescribed above in conjunction with FIG. 1, and wherein one or moreother sources of middle distillate feed are used for deep hydrogenation,including at least a portion of light coker gas oil 2334. The mediumrange middle distillates that are passed to the middle distillatehydrotreating zone 2150 can include a diesel range fraction, or afraction ranging from heavy kerosene through medium atmospheric gas oil.

The vacuum gas oil 2144, and in certain embodiments all or a portion ofatmospheric gas oil 2124, is treated in a gas oil hydroprocessing zone2160/2170 operating as a hydrocracking zone 2160 or as a hydrotreatingzone 2170. In embodiments in which gas oils are hydrocracked, thehydrocracking zone 2160 produces a naphtha fraction 2162 as part of thefeed to the steam cracking zone 2220, a middle distillate range fraction2164′ which can be used as a feed for hydrogenation, and an unconvertedoil fraction 2166. All or a portion of the unconverted oil 2166, forinstance a diverted flow of a full range of the unconverted oil, or alight portion of the unconverted oil, can be passed to the DHG zone2200. In embodiments in which gas oils are hydrotreated, thehydrotreating zone 2170 produces a hydrotreated naphtha fraction 2172 aspart of the feed to the steam cracking zone 2220, and hydrotreated gasoil 2176. All or a portion of the hydrotreated gas oil 2176, for adiverted flow of a full range of the hydrotreated gas oil, or a lightportion of the hydrotreated gas oil, can be passed to the DHG zone 2200.In certain embodiments, a middle distillate range fraction 2164′ is alsorecovered from the hydrotreating zone 2170 effluents. All or a portionof the middle distillate fraction 2164′ can be passed to the DHG zone2200. In certain embodiments, an additional hydrotreating reaction zonecan be included between the gas oil hydroprocessing zone 2160/2170 andthe DHG zone 2200, depending on the sulfur and nitrogen content of themiddle distillate fraction 2164′, and whether this stream is processedin the DHG zone 2200 alone or in combination with other middledistillate streams that have lower sulfur and nitrogen content. In theseembodiments, the catalyst used and operating conditions forhydrotreating can be similar to those of the diesel hydrotreating zone2150. In certain embodiments an in-line hydrotreater can be used afterthe gas oil hydroprocessing zone 2160/2170 as is known in the art,whereby the temperature and pressure variations between the gas oilhydroprocessing zone and the hydrotreater are minimized as the effluentsare passed in-line to one or more hydrotreating catalyst beds. Incertain embodiments all or a portion of the middle distillate fraction2164′ can be recovered as a diesel fuel blending component that can becompliant with Euro V diesel standards as described above in conjunctionwith FIG. 1, and wherein one or more other sources of middle distillatefeed are used for deep hydrogenation, including at least a portion oflight coker gas oil 2334.

In accordance with the process herein, the severity of the gas oilhydroprocessing operation 2160/2170 can be used to moderate the relativeyield of olefin and aromatic chemicals from the overall complex andimprove the economic threshold of cracking heavy feeds. This applicationof a gas oil hydroprocessing zone as a chemical yield control mechanism,is uncommon in the industry, where fuel products are typically theproduct objectives.

In certain embodiments a vacuum residue conditioning zone 2180 isintegrated for treatment of all or a portion of the vacuum residue 2144,for instance, producing a naphtha stream 2184 as part of the feed to thesteam cracking zone 2220, a middle distillate range fraction 2186′ whichcan be used as a feed for hydrogenation, an unconverted oil fraction2188, and pitch 2190.

In certain embodiments a middle distillates stream 2182 (instead of thediesel fraction or in conjunction therewith) is routed to the gas oilhydroprocessing zone 2160/2170 and/or the diesel hydrotreating zone2150. All or a portion of the middle distillate range fraction 2186′ canbe passed to the DHG zone 2200. In certain embodiments, an additionalhydrotreating reaction zone can be included between the vacuum residueconditioning zone 2180 and the DHG zone 2200, depending on the sulfurand nitrogen content of the middle distillate fraction 2186′, andwhether this stream is processed in the DHG zone 2200 alone or incombination with other middle distillate streams that have lower sulfurand nitrogen content. In these embodiments, the catalyst used andconditions within this additional hydrotreater can be similar to thoseof the diesel hydrotreating zone 2150. In certain embodiments an in-linehydrotreater can be used after the vacuum residue conditioning zone 2180as is known in the art, whereby the temperature and pressure variationsbetween the gas oil hydroprocessing zone and the hydrotreater areminimized as the effluents are passed in-line to one or morehydrotreating catalyst beds. In certain embodiments all or a portion ofthe middle distillate range fraction 2186′ can be recovered as a dieselfuel blending component that can be compliant with Euro V dieselstandards as described above in conjunction with FIG. 1, and wherein oneor more other sources of middle distillate feed are used for deephydrogenation, including at least a portion of light coker gas oil 2334.

All or a portion of the desulfurized middle distillate fractions withinthe system are routed to a deep hydrogenation zone 2200. In certainembodiments, all, a substantial portion, a significant portion or amajor portion of the middle distillate range fraction 2154′ from themiddle distillate hydrotreating zone 2150 is routed to the deephydrogenation zone 2200. In certain embodiments, all, a substantialportion, a significant portion or a major portion of the middledistillate range fraction 2164′ from the hydroprocessing zone 2160/1170is routed to the deep hydrogenation zone 2200. In certain embodiments,all, a substantial portion, a significant portion or a major portion ofthe middle distillate range fraction 2186′ from the vacuum residueconditioning zone 2180 is routed to the deep hydrogenation zone 2200.These streams can be combined, or the deep hydrogenation zone 2200 canoperate to hydrogenate one, two or all of these streams. The productsfrom the deep hydrogenation zone 2200, the hydrogenated middledistillate stream 2202, serves as feed to the steam cracker or steamcracker complex 2215, in certain embodiments combined with one or morenaphtha feeds.

In the embodiment of FIG. 2B, a system similar to that of FIG. 2A isschematically depicted, further integrating a naphtha hydrogenation zone2204 for hydrogenation of naphtha to produce a hydrogenated naphthastream 2206 as additional stream cracker feed.

In FIG. 2B, the combined naphtha stream 2222 is processed in a naphthahydrogenation zone 2204. In other embodiments (not shown), the wildnaphtha 2152 only is processed in the naphtha hydrogenation zone 2204.In further embodiments, all or a portion of the coker naphtha 2332 canbe used as feed to the naphtha hydrogenation zone 2204. In certainembodiments all or a portion of the coker naphtha 2332 is subjected tohydrotreating first to remove sulfur and nitrogen compounds prior tohydrogenation. Typically the coker naphtha 2332 stream contains olefincontent that makes it less desirable as a steam cracking feedstock, asthe higher olefin content leads to coking in the steam crackingoperation. However, the coker naphtha 2332 or hydrotreated coker naphtha2332 can be subjected to hydrogenation. In the embodiment of FIG. 2B,the coker naphtha 2332 or hydrotreated coker naphtha 2332 is passed tothe naphtha hydrogenation zone 2204 and thereby increase the steamcracking feed. In other embodiments, the coker naphtha 2332 orhydrotreated coker naphtha 2332 can be subjected to hydrogenation andthe hydrogenated product passed to aromatics recovery.

The naphtha hydrogenation zone 2204 can contain one or more fixed-bed,ebullated-bed, slurry-bed, moving bed, continuous stirred tank (CSTR) ortubular reactors, in series and/or parallel arrangement. In certainembodiments, multiple reactors can be provided in parallel in thenaphtha hydrogenation zone 2204 to facilitate catalyst replacementand/or regeneration. The reactor(s) are operated under conditionseffective for hydrogenation of the reduced organosulfur and reducedorganonitrogen middle distillate feed, the particular type of reactor,the feed characteristics, and the catalyst selection. Additionalequipment, including exchangers, furnaces, feed pumps, quench pumps, andcompressors to feed the reactor(s) and maintain proper operatingconditions, are well known and are considered part of the naphthahydrogenation zone 2204. In addition, equipment including pumps,compressors, high temperature separation vessels, low temperatureseparation vessels and the like to separate reaction products andprovide hydrogen recycle within the naphtha hydrogenation zone 2204, arewell known and are considered part of the naphtha hydrogenation zone2204.

In certain embodiments, the naphtha hydrogenation zone 2204 operatingconditions include:

a reaction temperature (° C.) in the range of from about 250-320,250-315, 250-310, 280-320, 280-315, 280-310, 285-320, 285-315, 285-310,290-320, 290-315, or 290-310;

a hydrogen partial pressure (barg) in the range of from about 20-85,20-70, 20-60, 30-85, 40-85 or 40-70;

a hydrogen to oil feed ratio (SLt/Lt) of up to about 3000, 2000 or 1500,in certain embodiments from about 500-3000, 500-2000, 500-1500,1000-3000, 1000-2000 or 1000-1500; and

a liquid hourly space velocity values (h⁻¹), on a fresh feed basisrelative to the hydrogenation catalysts, in the range of from about0.1-5.0, 0.1-3.0, 0.1-2.0, 0.5-5.0, 0.5-3.0, 0.5-2.0, 1.0-5.0, 1.0-5.0or 1.0-2.0.

An effective quantity of hydrogenation catalyst is provided in thenaphtha hydrogenation zone 2204 that is effective for hydrogenation ofnaphtha from the one or more naphtha sources.

Suitable hydrogenation catalysts contain one or more active metalcomponent of metals or metal compounds (oxides or sulfides) selectedfrom the Periodic Table of the Elements IUPAC Groups 7, 8, 9 and 10. Incertain embodiments the active metal component is selected from thegroup consisting of Pt, Pd, Ti, Rh, Re, Ir, Ru, and Ni, or a combinationthereof. In certain embodiments the active metal component comprises anoble metal selected from the group consisting of Pt, Pd, Rh, Re, Ir,and Ru, or a combination thereof. The combinations can be composed ofdifferent particles containing a single active metal species, orparticles containing multiple active species.

Such noble metals can be provided in the range of (wt % based on themass of the metal relative to the total mass of the catalyst) 0.01-5,0.01-2, 0.05-5, 0.05-2, 0.1-5, 0.1-2, 0.5-5, or 0.5-2. In certainembodiments, the catalyst particles have a pore volume in the range ofabout (cc/gm) 0.15-1.70, 0.15-1.50, 0.30-1.50 or 0.30-1.70; a specificsurface area in the range of about (m²/g) 100-400, 100-350, 100-300,150-400, 150-350, 150-300, 200-400, 200-350 or 200-300; and an averagepore diameter of at least about 10, 50, 100, 200, 500 or 1000 angstromunits.

The active metal component is typically deposited or otherwiseincorporated on a support such as amorphous alumina, and in certainembodiments non-acidic amorphous alumina. In certain embodiments thesupport comprises non-acidic amorphous alumina containing about 0.1-20,0.1-15, 0.1-10, 0.1-5, 0.5-20, 0.5-15, 0.5-10, 0.5-5, 1-20, 1-15, 1-10,2.5-20, 2.5-15, or 2.5-10 wt %, of zeolite, including USY zeolite.Non-acidic catalysts are selected for deep hydrogenation catalyst so asto favor hydrogenation reactions over hydrocracking reactions.Particularly effective hydrogenation catalyst to promote hydrogenationreactions include noble metal active catalyst components on non-acidicsupports, such as Pt, Pd or combinations thereof on non-acidic supports.In certain embodiments a suitable hydrogenation catalyst includes anon-acidic support such as alumina having Pt as the active metalcomponent in an amount of about 0.1-0.5 wt % based on the mass of themetal relative to the total mass of the catalyst, with relatively smallamounts of zeolite such as USY zeolite, for instance 0.1-5 wt %.

In certain embodiments, the hydrogenation catalyst and/or the catalystsupport is prepared in accordance with US Patents U.S. Pat. No.9,221,036B2 and U.S. Ser. No. 10/081,009B2, which are incorporatedherein by reference in their entireties. Such catalyst and/or catalystsupport includes a modified USY zeolite support having one or more ofTi, Zr and/or Hf substituting the aluminum atoms constituting thezeolite framework thereof. For instance, the catalyst effective for deephydrogenation include an active metal component carried on a supportcontaining an ultra-stable Y-type zeolite, wherein the aboveultra-stable Y-type zeolite is a framework-substituted zeolite (referredto as a framework-substituted zeolite) in which a part of aluminum atomsconstituting a zeolite framework thereof is substituted with 0.1-5 mass% zirconium atoms and 0.1-5 mass % Ti ions calculated on an oxide basis.

Hydrogenation catalysts using noble metal active catalyst components areeffective at relatively lower temperatures. As will be appreciated bythose having ordinary skill in the art, aromatic hydrogenation reactionsare more favorable at lower temperatures, whereas high temperatures arerequired for cracking. The delta temperature for cracking as compared tohydrogenation can be in the range of about 30-80° C.

In certain embodiments, any suitable feedstock, stream 3306 in FIG. 3,can be processed in a coking zone 3300 to produce typical coking zoneliquid and gas products, including light gases, coker naphtha and lightcoker gas oil as feed to a deep hydrogenation zone disclosed herein forconditioning as steam cracking feed. FIG. 3 schematically depicts anembodiment of a process and system 3100 for conversion of crude oil topetrochemicals and fuel products, integrating deep hydrogenation oflight coker gas oil. The several unit operations and streams are denotedas a “3000” series of reference numerals that are similar to thosedescribed in conjunction with FIG. 1. Unless otherwise noted, units andstreams with similar “1000” and “3000” series reference numbers aresimilar or identical.

The coker feedstock 3306 can be a heavy oil feedstock selected from thegroup consisting of atmospheric residue, vacuum residue, deasphaltedoil, demetallized oil, other heavy oil fractions, and combinationsthereof, and can be derived from crude oil, bitumens, oil sand, shaleoil, coal oils or biomass oils. In certain embodiments an heavy oil canhave an initial boiling point corresponding to that of VGO describedherein, an end point based on the characteristics of the heavy oilfraction. In further embodiments an additional feedstock can have aninitial boiling point of about 425-565, 450-565, 425-540, 450-540,425-530, 450-530, 425-510 or 450-510° C., in certain embodiments about425, 450 or 475° C., and an end point based on the characteristics ofthe heavy oil fraction.

The coking zone 3300 is operated receive the coker feed 3306 forconversion into at least light gases 3330, coker naphtha 3332, lightcoker gas oil 3334, heavy coker gas oil 3336 and petroleum coke 3338.Light gases 3330 can be integrated with the fuel gas system. In certainembodiments (not shown), gases 3330 can be routed to the separationunits within the steam cracking complex 3215, and/or LPGs can be routedto the steam cracking zone 3220.

In certain embodiments, all or a portion of the coker naphtha 3332 canbe processed as described herein in a py-gas hydrotreatment and recoverycenter 3270/3272, to increase the quantity of raffinate as additionalfeed to the steam cracking zone 3220. Any portion of the coker naphtha3332 that is not routed to the py-gas hydrotreatment and recovery center3270/3272, shown in dashed lines, can be hydrotreated and recovered forfuel production. For instance, in modalities in which the objective ismaximum petrochemical production, all, a substantial portion, asignificant portion or a major portion of the coker naphtha 3332 isrouted to the py-gas hydrotreatment and recovery center 3270/3272; theremainder, if any, is recovered for fuel production and incorporationinto a gasoline pool.

In additional embodiments, all or a portion of the fluid catalyticcracking naphtha 4306 is hydrotreated and recovered for fuel productionand incorporation into a gasoline pool. Optionally, a portion of thecoker naphtha 3332 that is not recovered for fuel production can beprocessed in the py-gas hydrotreatment and recovery center 3270/3272, asshown in dashed lines, to increase the quantity of raffinate asadditional feed to the steam cracking zone 3220.

Other products from the coker zone 3300 include light coker gas oil 3336and petroleum coke 3338. In certain embodiments, all, a substantialportion, a significant portion or a major portion of the light coker gasoil 3336 is used as feed to the deep hydrogenation zone 3200, alone orin combination with other feeds as described herein.

In certain embodiments, an additional hydrotreating reaction zone can beincluded between the coking zone 3300 and the DHG zone 4200, dependingon the sulfur and nitrogen content of the coker gas oil 3336, andwhether this stream is processed in the DHG zone 3200 alone or incombination with other middle distillate streams that have lower sulfurand nitrogen content. In these embodiments, the catalyst(s), temperatureand space velocity for hydrotreating can be similar to those of thediesel hydrotreating zone 1150 described herein, with a hydrogen partialpressure in the range of from about 50-120, 50-100, 50-90, 60-120,60-100, 60-90, 70-120, 70-100 or 70-90.

Referring to FIGS. 4, 5 and 6, the coking reaction and separation zonesintegrated herein, and variations thereto apparent to a person havingordinary skill in the art, are effective for thermal cracking of a cokerfeed. The coking zone can operate in accordance with known cokers usedin oil refineries, including more commonly delayed coker units, and incertain arrangements a fluid coking process. In general, cokingoperations are carbon rejection processes that are used to convert lowervalue atmospheric or vacuum distillation residue streams to lighterproducts, thermally cracked hydrocarbon products. Typically, thesethermally cracked hydrocarbon products can be hydrotreated and/orsubjected to other known treatment processes to produce transportationfuels such as gasoline and diesel, and increments of light productswhich can be further desulfurized, treated, and/or concentrated toproduce petrochemicals

Coking of residuum from heavy high sulfur, or sour, crude oils istypically carried out to convert part of the material to more valuableliquid and gas products. Typical coking processes include delayed cokingand fluid coking. The treatment of coke varies depending on the type ofcoking process and the quality of the coke. In certain embodiments, forinstance with delayed coking units, resulting coke is removed fromdrums, and is generally treated as a low value by-product or recoveredfor various uses depending upon its quality. In a fluid coking unit,coke is removed as particles and a portion is recycled to provide hotsurfaces for thermal cracking.

A delayed coking unit and its general process description is shown andschematically illustrated below. The coker feedstream is mixed withsteam and the mixture rapidly heated in a coking furnace to a cokingtemperature, and then fed to a coking drum. The hot mixed cokerfeedstream is maintained in the coke drum at coking conditions oftemperature and pressure where the feed decomposes or cracks to formcoke and volatile components. The volatile components are recovered asvapor and transferred to a coking product fractionator. One or moreheavy fractions of the coke drum vapors can be condensed, for example byquenching or heat exchange. In certain embodiments the coke drum vaporsare contacted with heavy gas oil in the coking unit productfractionator, and heavy fractions form all or part of a recycle oilstream having condensed coking unit product vapors and heavy gas oil. Incertain embodiments, heavy gas oil from the coking feed fractionator isadded to a flash zone of the fractionator to condense the heaviestcomponents from the coking unit product vapors. Delayed coking units aretypically configured with two or more parallel drums and operated in analternating swing mode if there are two drums, or in a sequentiallycyclic operating mode if there are three or more drums. Parallel cokingdrum trains, with two or more drums per train, are also possible. Whenthe coke drum is full of coke, the feed is switched to another drum, andthe full drum is cooled. Liquid and gas streams from the coke drum arepassed to a coking product fractionator for recovery. Any hydrocarbonvapors remaining in the coke drum are removed, for instance by steaminjection. The coke remaining in the drum is typically cooled with waterand then removed from the coke drum by conventional methods, such as byhydraulic and/or mechanical techniques to remove green coke from thedrum walls for recovery.

Referring to FIG. 4, an embodiment of a coking reaction and separationzone 4310, including a coking zone operating as a delayed coker and anassociated fractioning zone. In certain embodiments, the products arelight gases 4330, coker naphtha 4332, light coker gas oil 4334, heavycoker gas oil 4336 and petroleum coke 4338.

The coking reaction and separation zone 4310 includes a coking furnace4314, a coking reaction zone 4320 (shown as parallel coking drum 4322and 4324) and a coking product fractionator 4328. An optional coker feed4312 and/or a heavy coker gas oil recycle stream 4336 are in fluidcommunication with an inlet of the coking furnace 4314. A heatedfeedstream from an outlet of the coking furnace 4314 is in fluidcommunication with an inlet of the coking reaction zone 4320, and acoker liquid and gas stream 4326 is discharged from an outlet of thecoking reaction zone 4320. The outlet discharging the coker liquid andgas stream 4326 is in fluid communication with an inlet of the cokingproduct fractionator 4328. The fractionating zone 4328 includes asinlets one or more feed inlets in fluid communication the coker liquidand gas stream 4326, and one or more outlets discharging naphtha, lightolefins products and gas oil range coker products. The coking zone 4310also includes associated apparatus for removing coke 4338.

The coker feed is charged to the coking furnace 4314 where the contentsare rapidly heated to a coking temperature and then fed to the cokingdrum 4322 or 4324. The coking unit 4310 can be configured with two ormore parallel drums 4322 and 4324 and can be operated in a swing mode,such that when one of the drums is filled with coke, the feed istransferred to the empty parallel drum so that accumulated coke 4338 canbe recovered from the filled drum.

The coker liquid and gas stream 4326 from the coker drum 4322 or 4324 ispassed to the coking product fractionator 4328, which produces lightgases 4330, coker naphtha 4332, light coker gas oil 4334, and heavycoker gas oil 4336. In certain embodiments the coker feed stream 4312 isalso charged to the coking product fractionator 4328. The gas oil rangecoker products can be further separated into light coker gas oil andheavy coker gas oil (not shown). The heavy coker gas oil 4336 can berecycled as all or a portion of the coker furnace stream 4314. Anyhydrocarbon vapors remaining in the coke drum are removed by steaminjection. The coke is cooled with water and then removed from the cokedrum using hydraulic and/or mechanical means.

In operation of the delayed coker, the coker feed stream 4312, and heavycoker gas recycle oil steam 4336, are introduced as combined stream 4313into the coking furnace 4314 for heating to a predetermined temperatureor temperature range that is similar to the coking temperature indelayed coking configurations. In typical operations the temperature ofthe heated coker feedstream is closely monitored and controlled in thefurnace utilizing appropriately positioned thermocouples, or othersuitable temperature-indicating sensors to avoid or minimize theundesirable formation of coke in the tubes of the furnace. The sensorsand control of the heat source, such as open flame heaters, can beautomated as is known to those of skill of the art. For example, inknown delayed cokers, a fired furnace or heater with horizontal tubes isused to reach thermal cracking temperatures, for instance, in the rangeof about 425-650, 425-530, 425-510, 425-505, 425-500, 450-650, 450-530,450-510, 450-505, 450-500, 480-650, 480-530, 480-510, 480-505 or480-500° C. With a short residence time in the furnace tubes of thecoking furnace 4314, and with the addition of steam, coking of the feedmaterial on the furnace tubes is minimized or obviated, and coking isthereby “delayed” until it is discharged into relatively larger cokingdrums in the coking reaction zone 4320 downstream of the heater. Inaddition, the necessary heat for coking is provided in the cokingfurnace 4314.

The flow of the heated coker feedstream from the coking furnace 4314 isdirected into one of the coking drums 4322 or 4324 via a feed line byadjustment of an inlet control valve, for instance, a three-way valve.The coking unit process can be conducted as a semi-continuous process byproviding at least two vertical coking drums that are operated in swingmode. This allows the flow through the tube furnace to be continuous.The feedstream is switched from one to another of the at least twodrums. In a coking unit with two drums, one drum is on-line filling withcoke while the other drum is being steam-stripped, cooled, decoked,pressure checked and warmed up. The overhead vapors from the coke drumsflow from the drum used for thermal cracking to the fractionating zonein a continuous manner.

The coke drum is maintained at coking conditions of temperature andpressure where the feed decomposes or cracks to form coke and volatilecomponents. The hydrocracker bottom stream, which is rich in hydrogendue to its highly paraffinic and naphthenic nature, serves as a hydrogendonor during these cracking reactions, and advantageously stabilizesradicals during thermal cracking and as a result minimizes cokeformation.

The volatile components are recovered as vapor and transferred to thecoking unit product fractionator. In certain embodiments, heavy gas oilfrom the fractionator is added to the flash zone of the fractionator tocondense the heaviest components from the coking unit product vapors.The heaviest fraction of the coke drum vapors can be condensed by othertechniques, such as heat exchange. In certain embodiments, as incommercial operations, incoming vapors can be contacted with heavy gasoil in the coking unit product fractionator. Conventional heavy recycleoil includes condensed coking unit product vapors and unflashed heavygas oil.

When a drum 4322 or 4324 contains the predetermined maximum amount ofcoke, the inlet control valve is adjusted to direct the heated cokerfeedstream into the other drum 4324 or 4322. Substantially at the sametime, a coking drum outlet valve is adjusted so that the liquid and gasproducts are discharged through the appropriate line as the coker liquidand gas stream 4326 that is passed to the fractionating zone 4328. Anyhydrocarbon vapors remaining in the coke drum are typically removed bysteam injection. Typically, the coking zone 4310 includes associatedapparatus, for instance, hydraulic and/or mechanical cutters, wherebycoke is cooled with water and then removed from the coke drum usinghydraulic and/or mechanical cutters while that coking drum istemporarily decommissioned. Coke that is subsequently removed from adrum when it is out of service is schematically represented as lines4338.

The operating temperature (° C.) in the coking drums 4320 can range fromabout 425-650, 425-510, 425-505, 425-500, 450-650, 450-510, 450-505,450-500, 485-650, 485-510, 485-505, 485-500, 470-650, 470-510, 470-505or 470-500. The operating pressure (bars) in the coking drum can be inthe range of about 1-20, 1-10, or 1-3, and in certain embodiments ismildly super-atmospheric. In certain embodiments of the process, steamis introduced or injected with the heated residue into the cokingfurnace, for instance with a steam introduction rate of about 0.1-3,0.5-3 or 1-3 wt % relative to the heated residue, to increase thevelocity in the tube furnace, and to reduce the partial pressure of thefeedstock oil in the drum. The steam also serves to increase the amountof gas oil removed from the coke drums. Steam also assists in decokingof the tubes in the event of a brief interruption of the feed flow. Thecoking in each drum can occur in cycles, for instance, in the range ofabout 10-30, 10-24, 10-18, 12-30, 12-24, 12-18, 16-30, 16-24 or 16-18hours.

In certain embodiments, a fluid coking process is used, whereincirculated coke particles contact the feed and in which coking occurs onthe surface of the coke particles, for instance similar to aFlexicoking™ process commercially available from ExxonMobil. Referringto FIG. 5, an embodiment of a coking reaction and separation zone 5340,including a coking zone operating as a fluid coker and an associatedfractioning zone, is shown. In certain embodiments, the products are thelight gases 5330, coker naphtha 5332, light coker gas oil 5334, andheavy coker gas oil 5336 and coke 5338.

The coking reaction and separation zone 5340 includes a coking furnace5344, a coking reaction zone 5346 and a coking product fractionator5328. In addition, suitable systems are provided to facilitatecirculation of coke particles including a coke combusting zone 5350 anda fines separation zone 5354. An option coker feed 5342 and/or heavycoker gas oil 5336 are in fluid communication, as combined stream 5313with an inlet of the coking furnace 5344. A heated feedstream from anoutlet of the coking furnace 5344 is in fluid communication with aninlet of the coking reaction zone 5346, and a coker liquid and gasstream 5356 is discharged from an outlet of the coking reaction zone5346. The outlet discharging the coker liquid and gas stream 5356 is influid communication with an inlet of the coking product fractionator5328. Light gases 5330, coker naphtha 5332, light coker gas oil 5334,and heavy coker gas oil 5336 are discharged from outlets of the cokingproduct fractionator 5328. In some embodiments, the heavy coker gas oil5336 can be recycled to before the furnace as all or a portion ofcombined stream 5313.

The coker feed is charged to a coking furnace 5344 where the contentsare rapidly heated to a coking temperature and then fed to a coking drum5346. The coking reaction zone 5346 includes a reactor having one ormore inlets that receive a heated feedstream by spraying or othersuitable means of injection. A portion of the coke effluent 5348, inparticle form, is discharged via one or more outlets, and is in fluid orparticulate communication with the coke combusting zone 5350. Heatedcoke 5352 is discharged from one or more outlets of the coke combustingzone 5350, and is in fluid or particulate communication with one or moreinlets of the coking drum 5346.

The coker liquid and gas products are recovered as the coker liquid andgas stream 5356 from one or more outlets of the coking drum 5346,generally through a fines separation zone 5354 for recovery of fine cokeparticles. The coker liquid and gas stream 5356 is passed to the cokingproduct fractionator 5328, which produces the light gases 5330, cokernaphtha 5332, and coker gas oil 5354.

In operation of the fluid coking unit, the coker feedstream(s) and steamare introduced into the coking furnace 5344 for heating to apredetermined temperature or temperature range, for instance, typicallyat about the coking temperature. For example, a fired furnace or heaterwith horizontal tubes is used to reach temperature levels that are at orbelow thermal cracking temperatures, for instance, in the range (° C.)of about 425-650, 425-570, 425-525, 450-650, 450-570, 450-525, 485-650,485-570 or 485-525. With a short residence time in the furnace tubes ofthe coking furnace 5344, and with the addition of steam, coking of thefeed material on the furnace tubes is minimized or obviated. In thefluid coking unit, coking occurs on coke particles in the coker reactor5346. Further, additional heat for coking is provided by recirculatingcombusted heated coke particles 5352 in the coking drum 5346.

All or a portion of the coke product 5348 is burned to provideadditional heat for coking reactions to the feed into gases, distillateliquids, and coke. Coking occurs on the surface of circulating cokeparticles of coke. Coke is heated by burning the surface layers ofaccumulated coke in the coke combustion zone 5350, by partial combustionof coke produced. The products of coking are sent to the fractionatingzone after recovery of fine coke particles in the separation zone 5354.Steam can also be added at the bottom of the reactor (not shown), forinstance, in a scrubber to add fluidization and to strip heavy liquidssticking to the surface of coke particles before they are sent to theburner. Coke is deposited in layers on the fluidized coke particles inthe reactor. Air is injected into the burner for combustion to burn aportion of the coke produced in the reactor. A portion of the combustedparticles are returned to the reactor, heated coke 5352, and theremainder is drawn out as coke 5338.

The operating temperature (° C.) in the coking drum 5346 can range fromabout 450-760, 450-650, 450-570, 470-760, 470-650, 470-570, 510-760,510-650 or 510-570. The operating pressure (bars) can be in the range ofabout 1-20, 1-10 or 1-3, and in certain embodiments is mildlysuper-atmospheric. In certain embodiments of the process, steam isintroduced or injected with the heated residue into the coking furnace,for instance in an amount of about 0.1-3, 0.5-3 or 1-3 wt %.

In certain embodiments, a coking and separation zone is provided withunits similar to those shown in FIG. 4 or 5, with additional material toassist in the process. Referring to FIG. 6, a coking and separation zone6370 is shown operating as a delayed coker or a fluid coker. The cokingand separation zone 6370 generally includes a coking drum or vessel 6380that discharges a coker liquid and gas stream 6382 and coke 6338, forinstance removed as in the above descriptions from a delayed coker or asfluidized particles; a coking fractionator 6328 that discharges lightgases 6330, coker naphtha 6332, and light coker gas oil 6334, and heavycoker gas oil 6336; and a coking furnace 6376 that receives the anoptional initial feedstream 6372 and/or heavy coker gas oil stream 6336,as combined stream 6313. A source of additional material 6374 isprovided in fluid or particulate communication with the coking drum 6380inlet, for instance, via the initial feedstream. While schematicallyshown upstream of the coking furnace 6376, the additional material 6374can be added downstream of the coking furnace. In embodiments in whichthere is a coker recycle stream from the coking fractionator 6328 to thecoking drum or vessel 6380, the source of additional material can beintegrated in the fractionator so that the coker recycle stream containscatalyst material. The additional material 6374 can be added to thecoker feed, or admixed with use of a separate mixing zone, such as anin-line mixing apparatus or a separate mixing apparatus (not shown). Incertain embodiments (not shown), additional material 6374 can be meteredor otherwise charged directly to the coking drum or vessel 6380.

In embodiments in which additional material is catalyst material,suitable catalysts include those having functionality to stabilize thefree radicals formed by thermal cracking and to thereby enhance thermalcracking reactions. The catalyst material can be in homogeneousoil-soluble form, heterogeneous supported catalysts, or a combinationthereof.

In certain embodiments, the additional material 6374 is a heterogeneouscatalyst material that can be added to the fractionator bottoms priorcoking. Suitable heterogeneous catalyst materials include active metalsdeposited or otherwise incorporated on a support material. Theheterogeneous catalyst materials used in embodiments herein aregenerally granular in nature, and the support material can be selectedfrom the group consisting of silica, alumina, silica-alumina,titania-silica, molecular sieves, silica gel, activated carbon,activated alumina, silica-alumina gel, zinc oxide, clays (for instance,attapulgus clay), fresh catalyst materials (including zeolitic catalyticmaterials), used catalyst materials (including zeolitic catalyticmaterials), regenerated catalyst materials (including zeolitic catalyticmaterials) and combinations thereof. The active metals of theheterogeneous catalyst material include one or more active metalcomponents of metals or metal compounds (oxides or sulfides) selectedfrom the Periodic Table of the Elements IUPAC Groups 4, 5, 6, 7, 8, 9and 10. In certain embodiments, the active metal component can be one ormore metals or metal compounds (oxides or sulfides) including Mo, V, W,Cr or Fe. In certain embodiments the active metal component can beselected from the group consisting of vanadium pentoxide, molybdenumalicyclic and aliphatic carboxylic acids, molybdenum naphthenate, nickel2-ethylhexanoate, iron pentacarbonyl, molybdenum 2-ethyl hexanoate,molybdenum di-thiocarboxylate, nickel naphthenate and iron naphthenate.In certain embodiments, Mo and Mo compounds are used as the active metalcomponent of a heterogenous catalyst material. The heterogeneouscatalyst material is provided in particulate form of suitable dimension,such as granules, extrudates, tablets, or pellets, and may be formedinto various shapes such as spheres, cylinders, trilobes, quadrilobes ornatural shapes, possess average particle diameters (mm) of about0.01-4.0, 0.1-4.0, or 0.2-4.0, pore sizes (nm) of about 1-5,000 or5-5,000, possess pore volumes (cc/g) of about 0.08-1.2, 0.3-1.2 or0.5-1.2, in certain embodiments at least 1.0, and possess a surface areaof at least about 100 m²/g.

In embodiments in which additional material 6374 is heterogeneouscatalyst material, it can be added upstream of the coking furnace, or inan optional embodiment, downstream of the furnace. A mixing zone can beused to mix the catalyst and coker feed. In addition, as catalystmaterial can be metered or otherwise charged directly to the coking drumor vessel 6380, or metered or otherwise charged directly to thefractionating zone 6328, as noted herein. In embodiments in whichheterogeneous catalyst is used, the amount (ppmw) can be about 1-20,000,10-20,000, 100-20,000, 1-10,000, 10-10,000, 100-10,000, 1-5,000,10-5,000, 100-5,000, 1-1,000, 10-1,000 or 100-1,000 relative to theweight of the total coker feedstream (stream 6372), and can bedetermined as is known in the art, for instance based upon factorsincluding the characteristics of the crude oil and its residue, the typeof catalyst used and the coking unit operating conditions.

In certain embodiments, a homogenous catalyst is used. For instance,effective homogeneous catalysts include those that are oil-soluble andcontain one or more active metal components of metals or metal compounds(oxides, sulfides, or salts of organo-metal complexes) selected from thePeriodic Table of the Elements IUPAC Groups 4, 5, 6, 7, 8, 9 and 10. Incertain embodiments, homogeneous catalysts are or contain as an activemetal component a transition metal-based compound derived from anorganic acid salt or an organo-metal compound containing Mo, V, W, Cr orFe. In certain embodiments homogeneous catalysts can be, or contain anactive metal compound, that is selected from the group consisting ofvanadium pentoxide, molybdenum alicyclic and aliphatic carboxylic acids,molybdenum naphthenate, nickel 2-ethylhexanoate, iron pentacarbonyl,molybdenum 2-ethyl hexanoate, molybdenum di-thiocarboxylate, nickelnaphthenate and iron naphthenate. In certain embodiments, Mo and Mocompounds are used as homogenous catalyst material. The totalconcentration (ppmw, based on the total feedstock weight) of thecatalyst material can be in the range of 100-20,000, 300-20,000,500-20,000, 1,000-20,000, 100-5,000, 300-5,000, 500-5,000, 1,000-5,000,100-1,500, 300-1,500, 500-1,500, 1,000-1,500, 100-1,200, 300-1,200 or500-1,200.

The homogeneous catalyst can be added upstream of the coking furnace, orin an optional embodiment, downstream of the furnace. Since the catalystis homogeneous and oil-soluble, it can be added directly to the cokingzone or in certain embodiments to the fractionator. If the homogeneouscatalyst is prepared from metal oxides or conditioned before use, aseparate step is carried for catalyst preparation as is known in theart. The amount of catalyst material (ppmw) can range from 1-10,000,10-10,000, 100-10,000, 1-5,000, 10-5,000, 100-5,000, 1-1,000, 10-1,000,100-1,000, 1-100 or 10-100 relative to the weight of the total cokerfeedstream (stream 6372), and can be determined as is known in the art,for instance based upon factors including the characteristics of thecrude oil and its residue, the type of catalyst used and the coking unitoperating conditions.

In certain embodiments, the additional material used, alone or incombination with one or more types of catalyst materials, comprisesadsorbent material. In this regard, the disclosure of commonly ownedU.S. Pat. Nos. 9,023,192 and 9,234,146 are relevant and are incorporatedby reference herein in their entireties. For example, adsorbent materialis admixed with the coker feedstream(s) in a mixing zone, such as anin-line mixing apparatus or a mixer, to form a slurry of the cokerfeedstream(s) and adsorbent material. In certain optional embodiments, asource of catalyst material is provided along with the adsorbentmaterial in fluid or solid communication with the coking drum or vessel6380 inlet. The optional catalyst material can be admixed in the samemanner as the adsorbent material, or in a different manner. Inembodiments in which optional catalyst material is used, the types andquantities of catalyst described herein for use in coking operations areapplicable.

The adsorbent material and/or heterogeneous catalyst material can beadmixed with the coker feedstream(s) with or without a dedicated mixingzone. Other embodiments that are not shown are also possible. Theadsorbent material and/or heterogeneous catalyst material can be meteredor otherwise charged separately to the coking drum or vessel 6380,whereby a source of material is provided in particulate communication orfluid communication (in which the material is formed in a slurry) withthe coking drum or vessel 6380 inlet. In further embodiments, thefractionating zone is configured for handling of adsorbent materialand/or heterogeneous catalyst material, whereby a source of material isprovided in particulate communication or fluid communication (in whichthe adsorbent material is formed in a slurry) with the fractionatingzone 6328. The adsorbent material and/or heterogeneous catalyst materialis metered or otherwise charged directly to the fractionating zone 6328so that a coker recycle stream contains the adsorbent material and/orheterogeneous catalyst material, for instance similar to the processthat is disclosed in commonly owned US Patent U.S. Pat. No. 9,023,192B2,which is incorporated by reference herein in its entirety. Coke 6338,which contains adsorbent material that has adsorbed undesirablecontaminants and/or heterogeneous catalyst material, is recovered fromthe coking drum or vessel 6380.

The use of adsorbent material increases the quality of the thermallycracked distillates by removing some of the undesirable contaminants,for instance by selectively adsorbing sulfur- and/or nitrogen-containingcompounds. Handling of adsorbent material that has adsorbed undesirablecontaminants, and/or heterogeneous catalyst material, largely depends onthe type of coker unit deployed. For instance, in delayed coker units,the adsorbent material and/or heterogeneous catalyst material isdeposited with the coke on the inside surface of the coking drum(s). Ina fluid coking process, the adsorbent material and/or heterogeneouscatalyst material can pass with the coke particles that are discharged.

Effective adsorbent materials are selected from the group consisting ofsilica, alumina, silica-alumina, titania-silica, molecular sieves,silica gel, activated carbon, activated alumina, silica-alumina gel,zinc oxide, clays (for instance, attapulgus clay), fresh catalystmaterials (including zeolitic catalytic materials), spent catalystmaterials (including zeolitic catalytic materials), regenerated catalystmaterials (including zeolitic catalytic materials), and combinationsthereof. In certain embodiments adsorbent material comprises activatedcarbon, clays, or mixtures thereof, The material is provided inparticulate form of suitable dimension, such as granules, extrudates,tablets, or pellets, and may be formed into various shapes such asspheres, cylinders, trilobes, quadrilobes or natural shapes, possessaverage particle diameters (mm) of about 0.01-4.0, 0.1-4.0, or 0.2-4.0,pore sizes (nm) of about 1-5,000 or 5-5,000, possess pore volumes (cc/g)of about 0.08-1.2, 0.3-1.2 or 0.5-1.2, in certain embodiments at least1.0, and possess a surface area of at least about 100 m²/g. The quantity(weight basis, hydrocarbon to adsorbent) of the solid adsorbent materialused in the embodiments herein is about 1000:1-3:1, 200:1-3-1,100:1-3:1, 50:1-3:1, 20:1-3:1, 1000:1-3:1, 200:1-8:1, 100:1-8:1,50:1-8:1, 20:1-8:1, 1000:1-3:1, 200:1-10:1, 100:1-10:1, 50:1-10:1 or20:1-10:1.

The fractionating zone, such as 4328, 5328 or 6328 described herein,includes design features to enable separation of cracker products fromthe coking drums/vessels, including the coker distillate stream, thecoker gas oil stream, and in certain embodiments a coker recycle stream.Components of the fractionating zone that are not shown but which arewell-known can include feed/product and pump-around heat exchangers,charge heater(s), product strippers, cooling systems, hot and coldoverhead drum systems including re-contactors and off-gas compressors,and units for water washing of overhead condensing systems. Steam istypically injected to prevent cracking of heated feed. In certainembodiments, one or more flash vessels can be used as the fractionatingzone. For instance, a first flash vessel can separate gases, and incertain embodiments all or a portion of a coker distillate stream, and asecond flash vessel to separate a coker gas oil stream and thehydroprocessing feed and the coker recycle stream. In certainembodiments, in which a source of additional material is used and isintegrated in the fractionator so that the coker recycle stream containsthe additional material, the fractionator includes appropriate designfeatures.

The feeds to the fractionating zone, the coker liquid and gas stream4326, 5356 or 6382, can be introduced at different locations in thecolumns as is known. The effluents shown in the figures include thecoker naphtha streams 4332, 5332 or 6332, light gases stream 4330, 5330or 6330, light gas oil range coker products 4334, 5334, or 6334, andheavy gas oil range coker products 4336, 5336 or 6336.

The deep hydrogenation zones in the embodiments disclosed herein, 2200and 3200, operate under conditions effective for deep hydrogenation oflight coker gas oil (and in certain embodiments middle distillates fromone or more other sources within the system) for conversion of aromaticsinto cycloalkanes and other non-aromatic compounds and to produce thehydrogenated middle distillate streams 2202 and 3202. The sourcesinclude the light coker gas oil streams 2334 and 3334. In certainembodiments, other sources can be provided. For instance, in theembodiments of FIGS. 2A and 2B, one or more additional sources can beselected from the middle distillate fraction 2154′ from the middledistillate hydrotreating zone 2150, the middle distillate range fraction2164′ from the gas oil hydroprocessing zone 2160/1170, the middledistillate range fraction 2186′ from the vacuum residue conditioningzone 2180, and/or the light range middle distillate fraction 2118′ fromthe kerosene sweetening zone 2120. In certain embodiments as noted abovemiddle distillate fractions 2164′ and/or 2186′ can be subjected tohydrotreating depending on the sulfur and nitrogen content of the middledistillate fractions, and whether they are processed in the DHG zone2200 alone or in combination with other middle distillate streams thathave lower sulfur and nitrogen content.

The selection of catalysts, conditions and the like for deephydrogenation are dependent on the feed, the aromatic content, and thetypes of aromatics in the diesel range stream. The effluent streamcontains the hydrogenated diesel range compounds, and lighter fractions,that are passed to the steam cracker as additional feed. In certainembodiments, the selection of catalysts and conditions are suitable toreduce aromatic content in a diesel range feedstream from a range ofabout 10-40 wt % or greater, to a hydrogenated distillate rangeintermediate product having an aromatic content of less than about5-0.5, 5-1, 2.5-0.5, 2.5-1, or 1-0.5 wt %.

In certain embodiments, a naphtha fraction (not shown) can be obtainedfrom the DHG zones, which can be combined with other naphtha streams inthe system or processed separately. For example, in the embodiments ofFIGS. 2A and 2B, naphtha produced in the DHG zone can be combined withthe naphtha streams to contribute to the volume of the combined naphthastream 2222. In certain embodiments naphtha produced in the DHG zone ispassed together with the hydrogenated middle distillate stream 2202 and3202 for steam cracking. Effluent off-gases can also be passed with thehydrogenated middle distillate stream, or recovered from the DHG zoneand passed to the olefins recovery train, the saturated gas plant aspart of the other gases stream 2134 and 3134, and/or directly to a fuelgas system. LPG can be recovered from the DHG zone and routed to thesteam cracking zone, the olefins recovery train and/or the saturated gasplant. In certain embodiments shown with respect to FIGS. 2A and 2B, anyrecovered naphtha from the DHG zone can be routed through the crudecomplex, alone, or in combination with other wild naphtha fractions fromwithin the integrated process. In embodiments in which any recoverednaphtha is routed through the crude complex, all or a portion of the LPGproduced in the DHG zone can be passed with naphtha fraction, or can bepassed directly to the gas plant or a separate gas treatment zone. Incertain embodiments, all, a substantial portion or a significant portionof any naphtha produced in the DHG zone is routed to the steam crackingzone (directly or through the crude complex).

The DHG zone can contain one or more fixed-bed, ebullated-bed,slurry-bed, moving bed, continuous stirred tank (CSTR) or tubularreactors, in series and/or parallel arrangement. In certain embodiments,multiple reactors can be provided in parallel in DHG zone to facilitatecatalyst replacement and/or regeneration. The reactor(s) are operatedunder conditions effective for hydrogenation of the light coker gas oiland in certain embodiments in combination with reduced organosulfur andreduced organonitrogen middle distillate feed from other sources, andsuch conditions can vary based on, for instance, the particular type ofreactor, the feed characteristics, and the catalyst selection.Additional equipment, including exchangers, furnaces, feed pumps, quenchpumps, and compressors to feed the reactor(s) and maintain properoperating conditions, are well known and are considered part of the DHGzone. In addition, equipment including pumps, compressors, hightemperature separation vessels, low temperature separation vessels andthe like to separate reaction products and provide hydrogen recyclewithin the DHG zone, are well known and are considered part of the DHGzone.

In certain embodiments, the DHG zone operating conditions include:

a reaction temperature (° C.) in the range of from about 250-320,250-315, 250-310, 280-320, 280-315, 280-310, 285-320, 285-315, 285-310,290-320, 290-315, or 290-310;

a hydrogen partial pressure (barg) in the range of from about 20-100,20-85, 20-70, 30-100, 30-85, 30-40, 40-100, 40-85 or 40-70;

a hydrogen to oil feed ratio (SLt/Lt) of up to about 3000, 2000 or 1500,in certain embodiments from about 500-3000, 500-2000, 500-1500,1000-3000, 1000-2000 or 1000-1500; and

a liquid hourly space velocity values (h⁻¹), on a fresh feed basisrelative to the hydrogenation catalysts, in the range of from about0.1-5.0, 0.1-3.0, 0.1-2.0, 0.5-5.0, 0.5-3.0, 0.5-2.0, 1.0-5.0, 1.0-5.0or 1.0-2.0.

An effective quantity of hydrogenation catalyst is provided in the DHGzone that is effective for deep hydrogenation. Suitable hydrogenationcatalysts contain one or more active metal component of metals or metalcompounds (oxides or sulfides) selected from the Periodic Table of theElements IUPAC Groups 7, 8, 9 and 10. In certain embodiments the activemetal component is selected from the group consisting of Pt, Pd, Ti, Rh,Re, Ir, Ru, and Ni, or a combination thereof. In certain embodiments theactive metal component comprises a noble metal selected from the groupconsisting of Pt, Pd, Rh, Re, Ir, and Ru, or a combination thereof. Thecombinations can be composed of different particles containing a singleactive metal species, or particles containing multiple active species.Such noble metals can be provided in the range of (wt % based on themass of the metal relative to the total mass of the catalyst) 0.01-5,0.01-2, 0.05-5, 0.05-2, 0.1-5, 0.1-2, 0.5-5, or 0.5-2. In certainembodiments, the catalyst particles have a pore volume in the range ofabout (cc/gm) 0.15-1.70, 0.15-1.50, 0.30-1.50 or 0.30-1.70; a specificsurface area in the range of about (m²/g) 100-400, 100-350, 100-300,150-400, 150-350, 150-300, 200-400, 200-350 or 200-300; and an averagepore diameter of at least about 10, 50, 100, 200, 500 or 1000 angstromunits.

The active metal component is typically deposited or otherwiseincorporated on a support such as amorphous alumina, and in certainembodiments non-acidic amorphous alumina. In certain embodiments thesupport comprises non-acidic amorphous alumina containing about 0.1-20,0.1-15, 0.1-10, 0.1-5, 0.5-20, 0.5-15, 0.5-10, 0.5-5, 1-20, 1-15, 1-10,2.5-20, 2.5-15, or 2.5-10 wt %, of zeolite, including USY zeolite.Non-acidic catalysts are selected for deep hydrogenation catalyst so asto favor hydrogenation reactions over hydrocracking reactions.Particularly effective deep hydrogenation catalyst to promotehydrogenation reactions include noble metal active catalyst componentson non-acidic supports, such as Pt, Pd or combinations thereof onnon-acidic supports. In certain embodiments a suitable deephydrogenation catalyst includes a non-acidic support such as aluminahaving Pt as the active metal component in an amount of about 0.1-0.5 wt% based on the mass of the metal relative to the total mass of thecatalyst, with relatively small amounts of zeolite such as USY zeolite,for instance 0.1-5 wt %.

In certain embodiments, the catalyst and/or the catalyst support isprepared in accordance with US Patents U.S. Pat. No. 9,221,036B2 andU.S. Ser. No. 10/081,009B2, which are incorporated herein by referencein their entireties. Such catalyst and/or catalyst support includes amodified USY zeolite support having one or more of Ti, Zr and/or Hfsubstituting the aluminum atoms constituting the zeolite frameworkthereof. For instance, the catalyst effective for deep hydrogenationinclude an active metal component carried on a support containing anultra-stable Y-type zeolite, wherein the above ultra-stable Y-typezeolite is a framework-substituted zeolite (referred to as aframework-substituted zeolite) in which a part of aluminum atomsconstituting a zeolite framework thereof is substituted with 0.1-5 mass% zirconium atoms and 0.1-5 mass % Ti ions calculated on an oxide basis.

Catalyst using noble metal active catalyst components are effective atrelatively lower temperatures. As will be appreciated by those havingordinary skill in the art, aromatic hydrogenation reactions are morefavorable at lower temperatures, whereas high temperatures are requiredfor cracking. The delta temperature for cracking as compared tohydrogenation can be in the range of about 30-80° C.

In certain embodiments, the feedstock to the reactor within the DHG zone(a single reactor with one bed, a single reactor with multiple beds, ormultiple reactors) is mixed with an excess of hydrogen gas in a mixingzone. A portion of the hydrogen gas is mixed with the feedstock toproduce a hydrogen-enriched liquid hydrocarbon feedstock. Thishydrogen-enriched liquid hydrocarbon feedstock and undissolved hydrogencan be supplied to a flashing zone in which at least a portion ofundissolved hydrogen is flashed, and the hydrogen is recovered andrecycled. The hydrogen-enriched liquid hydrocarbon feedstock from theflashing zone is supplied as a feed stream to the reactor(s) of the DHGzone.

In certain embodiments, the steam cracking complex integrated in theembodiments of FIGS. 2A, 2B, and 3 includes one or more units for steamcracking of the combination of the naphtha range feeds and the middledistillate range feeds. Products from the steam cracking zone include aquenched cracked gas stream containing mixed C1-C4 paraffins and olefinsthat is routed to the olefins recovery zone, a pyrolysis gasolinestream, and a pyrolysis fuel oil stream, which can be handled asdescribed herein with respect to the streams 1224, 1228 and 1226described in conjunction with FIG. 1, or as otherwise known.

With reference to FIG. 7, another embodiment of a steam cracking zone isshown, which can be integrated in the embodiments of FIGS. 2A, 2B, and3. A steam cracking zone 7220′ includes multiple units for processingfeedstocks having different boiling point characteristics. For instance,the steam cracking zone 7220′ is shown including a naphtha steamcracking section 7284 and a middle distillate steam cracking section7292.

The naphtha steam cracking section 7284 is operated under conditionseffective for conversion of the feed, the combined naphtha stream 7222or the hydrogenated combined naphtha stream 7206, into a major portionof light olefins, and minor portions of pyrolysis gasoline and pyrolysisoil. The naphtha steam cracking section 7284 can include operations thesame or similar to that of the steam cracking zone 1220 described inconjunction with FIG. 1. Products from the naphtha steam crackingsection 7284 include a quenched cracked gas stream 7286 containing mixedC1-C4 paraffins and olefins that is routed to the olefins recovery zone,a pyrolysis gasoline stream 7288, and a pyrolysis fuel oil stream 7290,which can be handled as described herein with respect to the streams1224, 1228 and 1226 described in conjunction with FIG. 1.

The middle distillate steam cracking section 7292 is operated underconditions effective for conversion of the feed, hydrogenated middledistillate stream 7202, into a major portion of light olefins, and minorportions of pyrolysis gasoline and pyrolysis oil. Products from themiddle distillate steam cracking section 7292 include a quenched crackedgas stream 7294 containing mixed C1-C4 paraffins and olefins that isrouted to the olefins recovery zone, a pyrolysis gasoline stream 7296,and a pyrolysis fuel oil stream 7298, which can be handled as describedherein with respect to the streams 1224, 1228 and 1226 described inconjunction with FIG. 1.

In certain embodiments, the quenched cracked gas streams 7286 and 7294are combined and treated in a common olefins recovery zone as describedherein with respect to the gas stream 1224. The pyrolysis gasolinestreams can be treated separately, or the fraction derived from middledistillate steam cracking can be pretreated before combining for acommon treatment, for instance as described herein with respect to thepyrolysis gasoline stream 1228. The pyrolysis oil streams can be treatedseparately, or the fraction derived from middle distillate steamcracking can be pretreated before combining for a common treatment, forinstance as described herein with respect to the pyrolysis oil stream1226. In other embodiments the pyrolysis oil stream obtained fromnaphtha cracking can be divided into heavy pyrolysis oil and lightpyrolysis oil, and where the heavy pyrolysis oil from naphtha crackingis combined with the pyrolysis oil stream obtained from middledistillate cracking.

The middle distillate steam cracking section 7292 can be operated underparameters effective to crack the feed into desired products includingethylene, propylene, butadiene, and mixed butenes. Pyrolysis gasolineand pyrolysis oil are also recovered. In certain embodiments, the steamcracking furnace(s) in the middle distillate steam cracking section 7292are operated at conditions effective to produce an effluent having apropylene-to-ethylene weight ratio of from about 0.3-0.8, 0.3-0.6,0.4-0.8 or 0.4-0.

In one embodiment of the middle distillate steam cracking section 7292,hydrogenated middle distillate stream 7202 and the hydrogenated middledistillate stream 7202 is preheated and mixed with a dilution steam toreduce hydrocarbon partial pressure in a convection section. Thesteam-hydrocarbon mixture is heated further and fed to tubular reactorsmounted in the radiant sections of the cracking furnaces. Thehydrocarbons undergo free-radical pyrolysis reactions to form lightolefins, ethylene and propylene, and other by-products.

In certain embodiments, steam cracking in the middle distillate steamcracking section 7292 is carried out using the following conditions: atemperature (° C.) in the convection section in the range of about300-450 or 300-400; a pressure (barg) in the convection section in therange of about 7.2-9.7, 7.2-8.5, 7.2-7.7, 7.7-8.5, 7.7-9.7 or 8.5-9.7; atemperature (° C.) in the pyrolysis section in the range of about700-850, 700-800, 700-820, 750-850, 750-800 or 750-820; a pressure(barg) in the pyrolysis section in the range of about 0.9-1.2, 0.9-1.4,0.9-1.6, 1.2-1.4, 1.2-1.6 or 1.4-1.6; a steam-to-hydrocarbon ratio inthe convection section in the range of about 0.75:1-2:1, 0.75:1-1.5:1,0.85:1-2:1, 0.9:1-1.5:1, 0.9:1-2:1, 1:1-2:1 or 1:1-1.5:1; and aresidence time (seconds) in the pyrolysis section in the range of about0.02-1, 0.02-0.08, 0.02-0.5, 0.1-1, 0.1-0.5, 0.2-0.5, 0.2-1, or 0.5-1.

In certain embodiments, cracked gas from the middle distillate steamcracking zone furnaces is quenched in transfer line exchangers byproducing, for instance, 1800 psig steam. Quenched gases are strippedwith steam in a primary fractionator. Lighter gases are recovered as theoverhead product; a side-draw stream contains pyrolysis fuel oil. Theprimary fractionator bottoms product is pyrolysis tar, which is cooledand sent to product storage. Pyrolysis fuel oil from the primaryfractionator is stripped with steam in the pyrolysis fuel oil stripper,which separates pyrolysis gasoline as the overhead and pyrolysis fueloil as the bottoms product. Gasoline in the primary fractionatoroverhead is condensed and combined with gasoline from the pyrolysis fueloil stripper before being sent to a gasoline stabilizer. The gasolinestabilizer removes light products in the overhead, while the stabilizerbottoms are sent to the py-gas hydrotreater. C4 and lighter gases in theprimary fractionator overhead are compressed, for instance, in twostages of compression, before entering an absorber, depropanizer anddebutanizer.

Compression of C4 and lighter gases from both the naphtha steam crackingzone 7284 and the middle distillate steam cracking section 7292 can becarried out in certain embodiments in a common step, to reduce capitaland operating costs associated with compression, thereby increasingefficiencies in the integrated process herein. Accordingly, both the C4and lighter gas streams from both steam cracking zones can be passed toan olefins recovery zone, operating for instance as described withrespect to the olefins recovery zone 1230.

In certain embodiments, cracked gas from the furnaces of both thenaphtha steam cracking zone 7284 and the middle distillate steamcracking section 7292 are subjected to common steps for quenching,recovery of pyrolysis gasoline, recovery of pyrolysis oil, and recoveryof C4 and lighter gases. For instance, in one embodiment, the crackedgas from the furnaces of both steam cracking zones are combined cooledin transfer line exchangers (quench coolers), for example, producing1800 psig steam suitable as dilution steam. Quenched cracked gas entersa primary fractionator for removal of pyrolysis fuel oil bottoms fromlighter components. The primary fractionator enables efficient recoveryof pyrolysis fuel oil. Pyrolysis fuel oil is stripped with steam in afuel oil stripper to control product vapor pressure and cooled. Inaddition, secondary quench can be carried out by direct injection ofpyrolysis fuel oil as quench oil into liquid furnace effluents. Thestripped and cooled pyrolysis fuel oil can be sent to a fuel oil pool orproduct storage. The primary fractionator overhead is sent to a quenchwater tower; condensed dilution steam for process water treating, andraw pyrolysis gasoline, are recovered. Quench water tower overhead issent to an olefins recovery zone, particularly the first compressionstage. Raw pyrolysis gasoline is sent to a gasoline stabilizer to removeany light ends and to control vapor pressure in downstream pyrolysisgasoline processing. A closed-loop dilution steam/process water systemis enabled, in which dilution steam is generated using heat recoveryfrom the primary fractionator quench pumparound loops. The primaryfractionator enables efficient recovery of pyrolysis fuel oil due toenergy integration and pyrolysis fuel oil content in the light fractionstream.

Advantageously, process dynamics of the configurations and theintegration of units and streams attain a very high level of integrationof utility streams between the steam cracking and other process units,result in increased efficiencies and reduced overall operating costs.

For instance, the hydrogen can be tightly integrated so that the nethydrogen demand from outside of the battery limits is reduced, forinstance in the deep hydrogenation zone 2200. Furthermore, theintegrated process described herein offers useful outlets for theoff-gases and light ends from the hydroprocessing units. For instance,the stream 2134 that is passed to the saturated gas plant 2130 of thecrude complex 2105 can contain off-gases and light ends from thehydroprocessing units, such as the deep hydrogenation zone 2200, thediesel hydrotreating zone 2150, the gas oil hydroprocessing zone2160/2170 and/or from the optional residue treatment zone 2180. In otherembodiments, in combination with or as an alternative to the passingthese off-gases and light ends to stream 2134, all or a portion can berouted to the steam cracking zone 2220. For instance, C2s can beseparated from the mixture of methane, hydrogen and C2s using a colddistillation section (“cold box”) including cryogenicdistillation/separation operations, which can be integrated with any orall of the steam cracking zone 2220, the saturated gas plant 2130 and/orthe olefins recovery zone 2230. Methane and hydrogen can be passed to afuel gas system or to an appropriate section of the olefins recoveryzone 2230, such as the hydrogen purification system. In still furtherembodiments, in combination with or as an alternative to the passingthese off-gases and light ends to stream 2134 and/or routing them to thesteam cracking zone 2220, all or a portion can be routed to anappropriate section of the olefins recovery zone 2230, such as thedepropanizer, or combining the gases with the depropanizer overheads.

The unique configurations presented herein set forth a level ofintegration, of streams and units that allows the use of delayed cokingunits and steam crackers in an economically efficient manner. Theconfigurations support and enhance chemical conversion using integratedprocesses with crude oil as a feed. Accordingly, despite the use ofcrude oil as the feed, the processes herein are comparable to otheroptions currently common in the industry such as ethane crackers thatbenefit from availability of ethane as a feed.

Embodiments described herein provide the ability to achieve a crude tochemical conversion ratio in the range of, for instance, up to 90, 80,50 or 45 wt %, and in certain embodiments in the range of about 39-45 wt%. It should be appreciated that this crude to chemicals conversionratio can vary depending on criteria such as feed, selected technology,catalyst selection and operating conditions for the individual unitoperations.

In some embodiments, individual unit operations can include a controllerto monitor and adjust the product slate as desired. A controller candirect parameters within any of the individual unit operations of theapparatus depending upon the desired operating conditions, which may,for example, be based on customer demand and/or market value. Acontroller can adjust or regulate valves, feeders or pumps associatedwith one or more unit operations based upon one or more signalsgenerated by operator data input and/or automatically retrieved data.

Such controllers provide a versatile unit having multiple modes ofoperation, which can respond to multiple inputs to increase theflexibility of the recovered product. The controller can be implementedusing one or more computer systems which can be, for example, ageneral-purpose computer. Alternatively, the computer system can includespecially-programmed, special-purpose hardware, for example, anapplication-specific integrated circuit (ASIC) or controllers intendedfor a particular unit operation within a refinery.

The computer system can include one or more processors typicallyconnected to one or more memory devices, which can comprise, forexample, any one or more of a disk drive memory, a flash memory device,a RAM memory device, or other device for storing data. The memory istypically used for storing programs and data during operation of thesystem. For example, the memory can be used for storing historical datarelating to the parameters over a period of time, as well as operatingdata. Software, including programming code that implements embodimentsof the invention, can be stored on a computer readable and/or writeablenonvolatile recording medium, and then typically copied into memorywherein it can then be executed by one or more processors. Suchprogramming code can be written in any of a plurality of programminglanguages or combinations thereof.

Components of the computer system can be coupled by one or moreinterconnection mechanisms, which can include one or more busses, forinstance, between components that are integrated within a same device,and/or a network, for instance, between components that reside onseparate discrete devices. The interconnection mechanism typicallyenables communications, for instance, data and instructions, to beexchanged between components of the system.

The computer system can also include one or more input devices, forexample, a keyboard, mouse, trackball, microphone, touch screen, andother man-machine interface devices as well as one or more outputdevices, for example, a printing device, display screen, or speaker. Inaddition, the computer system can contain one or more interfaces thatcan connect the computer system to a communication network, in additionor as an alternative to the network that can be formed by one or more ofthe components of the system.

According to one or more embodiments of the processes described herein,the one or more input devices can include sensors and/or flow meters formeasuring any one or more parameters of the apparatus and/or unitoperations thereof. Alternatively, one or more of the sensors, flowmeters, pumps, or other components of the apparatus can be connected toa communication network that is operatively coupled to the computersystem. Any one or more of the above can be coupled to another computersystem or component to communicate with the computer system over one ormore communication networks. Such a configuration permits any sensor orsignal-generating device to be located at a significant distance fromthe computer system and/or allow any sensor to be located at asignificant distance from any subsystem and/or the controller, whilestill providing data therebetween. Such communication mechanisms can beaffected by utilizing any suitable technique including but not limitedto those utilizing wired networks and/or wireless networks andprotocols.

Although the computer system is described above by way of example as onetype of computer system upon which various aspects of the processesherein can be practiced, it should be appreciated that the invention isnot limited to being implemented in software, or on the computer systemas exemplarily described. Indeed, rather than implemented on, forexample, a general purpose computer system, the controller, orcomponents or subsections thereof, can alternatively be implemented as adedicated system or as a dedicated programmable logic controller (PLC)or in a distributed control system. Further, it should be appreciatedthat one or more features or aspects of the processes can be implementedin software, hardware or firmware, or any combination thereof. Forexample, one or more segments of an algorithm executable by a controllercan be performed in separate computers, which in turn, can be incommunication through one or more networks.

In some embodiments, one or more sensors and/or flow meters can beincluded at locations throughout the process, which are in communicationwith a manual operator or an automated control system to implement asuitable process modification in a programmable logic controlledprocess. In one embodiment, a process includes a controller which can beany suitable programmed or dedicated computer system, PLC, ordistributed control system. The flow rates of certain product streamscan be measured, and flow can be redirected as necessary to meet therequisite product slate.

Factors that can result in various adjustments or controls includecustomer demand of the various hydrocarbon products, market value of thevarious hydrocarbon products, feedstock properties such as API gravityor heteroatom content, and product quality (for instance, gasoline andmiddle distillate indicative properties such as octane number forgasoline and cetane number for middle distillates).

The disclosed processes and systems create new outlets for directconversion of crude oil. Additionally, the disclosed processes andsystems offer novel configurations that, compared to known processes andsystems, requires lower capital expenditure relative to conventionalapproaches of chemical production from fuels or refinery by-products andthat utilize refining units and an integrated chemicals complex. Thedisclosed processes and systems substantially increase the proportion ofcrude oil that is converted to high purity chemicals that traditionallycommand high market prices. Complications resulting from advancing thethreshold of commercially proven process capacities are minimized oreliminated using the processes and systems described herein.

In certain embodiments, feedstock to the reactor(s) within one or moreof the hydrocracking, hydrotreating or other hydroprocessing zonesdescribed herein (a single reactor with one bed, a single reactor withmultiple beds, or multiple reactors) is mixed with an excess of hydrogengas in a mixing zone. A portion of the hydrogen gas is mixed with thefeedstock to produce a hydrogen-enriched liquid hydrocarbon feedstock.This hydrogen-enriched liquid hydrocarbon feedstock and undissolvedhydrogen can be supplied to a flashing zone in which at least a portionof undissolved hydrogen is flashed, and the hydrogen is recovered andrecycled. The hydrogen-enriched liquid hydrocarbon feedstock from theflashing zone is supplied as a feed stream to the reactor. The liquidproduct stream that is recovered from the reactor is further processedand/or recovered as provided here.

Each of the processing units are operated at conditions typical for suchunits, with conditions which can be varied based on the type of feed tomaximize, within the capability of the unit's design, the desiredproducts. Desired products can include fractions suitable as feedstockto the steam cracking zone 2220, or fractions suitable for use as fuelproducts. Likewise, processing units employ appropriate catalyst(s)depending upon the feed characteristics and the desired products.Certain embodiments of these operating conditions and catalysts aredescribed herein, although it shall be appreciated that variations arewell known in the art and are within the capabilities of those skilledin the art.

For the purpose of the simplified schematic illustrations anddescriptions herein, accompanying components that are conventional incrude centers, such as the numerous valves, temperature sensors,preheater(s), desalting operation(s), and the like are not shown ordescribed. In addition, accompanying components that are in conventionalhydroprocessing units such as, for example, hydrogen recyclesub-systems, bleed streams, spent catalyst discharge sub-systems, andcatalyst replacement sub-systems the like are not shown or described.Further, the numerous valves, temperature sensors, electroniccontrollers and the like that are conventional in fluid catalystcracking are not included. Further, accompanying components that are inconventional in fluid catalyst cracking systems such as, for example,air supplies, catalyst hoppers, flue gas handling the like are also notshown. Further, accompanying components that are in conventional thermalcracking systems such as steam supplies, coke removal sub-systems,pyrolysis sections, convection sections and the like are not shown ordescribed.

The methods and systems of the present invention have been describedabove and in the attached drawings; however, modifications will beapparent to those of ordinary skill in the art and the scope ofprotection for the invention is to be defined by the claims that follow.

The invention claimed is:
 1. A process for petrochemical productioncomprising: providing a heavy oil feedstock; subjecting the heavy oilfeedstock to coking to produce at least light coker gas oil; subjectingthe light coker gas oil to hydrogenation to hydrogenate aromaticscontained in the light coker gas oil and produce hydrogenated middledistillates, wherein hydrogenation occurs in the presence ofhydrogenation catalyst that contains one or more active metal componentsselected from Pt, Pd, Re and a combination comprising at least two ofPt, Pd or Re, and includes a catalyst support comprising non-acidicamorphous alumina and about 0.1-15 wt % of a modified USY zeolite havingone or more of Ti, Zr and/or Hf substituting aluminum atoms constitutingthe zeolite framework thereof; and subjecting the hydrogenated middledistillates to thermal cracking in a steam cracking complex to obtainlight olefins.
 2. The process as in claim 1, wherein the heavy oilfeedstock is selected from the group consisting of atmospheric residue,deasphalted oil, demetallized oil, coker gas oil, gas oil obtained froma visbreaking process, and combinations comprising at least one of theforegoing heavy oils.
 3. The process as in claim 1, further comprisinghydrotreating the light coker gas oil to produce hydrotreated lightcoker gas oil, and subjecting the hydrotreated light coker gas oil tohydrogenation.
 4. The process as in claim 1, further comprising thermalcracking further produces pyrolysis gasoline, the process furthercomprising passing the pyrolysis gasoline to hydrotreating to producehydrotreated pyrolysis gasoline, separating the hydrotreated pyrolysisgasoline into a raffinate stream that is recycled to the steam crackingcomplex and an extract stream that is used for BTX recovery.
 5. Theprocess as in claim 4, further wherein coking produces coker naphtha,and wherein the coker naphtha is separated together with thehydrotreated pyrolysis gasoline.
 6. The process as in claim 4, furtherwherein coking produces coker naphtha, the process further comprisinghydrotreating the coker naphtha produced by coking to producehydrotreated coker naphtha, and wherein the hydrotreated coker naphthais separated together with the hydrotreated pyrolysis gasoline.
 7. Theprocess as in claim 1, wherein coking is with a delayed coker.
 8. Theprocess as in claim 7, further wherein the delayed coker operatingconditions include a temperature of about 425-650° C.; a pressure ofabout 1-20 bars, and a steam introduction rate of about 0.1-3 wt %relative to the feedstock.
 9. The process as in claim 1, wherein cokingis with a fluid coker.
 10. The process as in claim 9, further whereinthe fluid coker operating conditions include a temperature of about450-760° C.; a pressure of about 1-20 bars; and a steam introductionrate of about 0.1-3 wt % relative to the feedstock.
 11. The process asin claim 1, wherein adsorbent material or catalytic material is added tothe coking zone.
 12. The process as in claim 11, wherein catalyticmaterial is added, and wherein catalytic material is a heterogeneouscatalyst selected from the group consisting of silica, alumina,silica-alumina, titania-silica, molecular sieves, silica gel, activatedcarbon, activated alumina, silica-alumina gel, zinc oxide, clays, freshcatalyst materials, used catalyst materials, regenerated catalystmaterials and combinations thereof.
 13. The process as in claim 12,wherein the heterogeneous catalyst incudes one or more active metalcomponents of metals or metal compounds selected from the Periodic Tableof the Elements IUPAC Groups 4, 5, 6, 7, 8, 9 and
 10. 14. The process asin claim 13, wherein the active metal component is a metal or metalcompound selected from the group consisting of vanadium pentoxide,molybdenum alicyclic and aliphatic carboxylic acids, molybdenumnaphthenate, nickel 2-ethylhexanoate, iron pentacarbonyl, molybdenum2-ethyl hexanoate, molybdenum di-thiocarboxylate, nickel naphthenate,iron naphthenate and combinations thereof.
 15. The process as in claim11, wherein catalytic material is added, and wherein catalytic materialis a homogeneous catalyst that is oil-soluble and contains one or moreactive metal components of metals or metal compounds selected from thePeriodic Table of the Elements IUPAC Groups 4, 5, 6, 7, 8, 9 and
 10. 16.The process as in claim 15, wherein the homogeneous catalyst is, orcontains as an active metal component, a transition metal-based compoundderived from an organic acid salt or an organo-metal compound containingMo, V, W, Cr, Fe and combinations thereof.
 17. The process as in claim15, wherein the homogeneous catalyst is, or contains as an active metalcompound, selected from the group consisting of vanadium pentoxide,molybdenum alicyclic and aliphatic carboxylic acids, molybdenumnaphthenate, nickel 2-ethylhexanoate, iron pentacarbonyl, molybdenum2-ethyl hexanoate, molybdenum di-thiocarboxylate, nickel naphthenate,iron naphthenate and combinations thereof.
 18. The process as in claim11, wherein adsorbent material is added, and wherein adsorbent materialis selected from the group consisting of silica, alumina,silica-alumina, titania-silica, molecular sieves, silica gel, activatedcarbon, activated alumina, silica-alumina gel, zinc oxide, clays, freshcatalyst materials, spent catalyst materials, regenerated catalystmaterials, and combinations thereof.
 19. The process as in claim 1,wherein hydrogenation occurs at a hydrogen partial pressure of about50-150 barg.
 20. The process as in claim 1, wherein hydrogenation occursat a reaction temperature of about 250-400° C.
 21. The process as inclaim 1, wherein hydrogenation occurs at a liquid hourly space velocityvalues, on a fresh feed basis relative to the hydrogenation catalysts,of about 0.1-5.0 h⁻¹.
 22. The process as in claim 1, whereinhydrogenation occurs at a hydrogen to oil feed ratio of about 100-1500SLt/Lt.
 23. The process as in claim 1, wherein hydrogenation occurs: ata hydrogen partial pressure of about 50-150 barg; at a reactiontemperature of about 250-400° C.; at a liquid hourly space velocityvalues, on a fresh feed basis relative to the hydrogenation catalysts,of about 0.1-5.0 h⁻¹; and at a hydrogen to oil feed ratio of about100-1500 SLt/Lt.
 24. The process as in claim 1, wherein the light cokergas oil contains at least about 10 wt % aromatics, and wherein thehydrogenated middle distillates contain less than about 1 wt %aromatics.
 25. A system for petrochemical production comprising: asource of heavy oil feedstock; a coking zone operable to thermally crackheavy oil from the source of heavy oil feedstock and to produce at leastlight coker gas oil; a fixed-bed hydrogenation zone operable to producehydrogenated middle distillates from the light coker gas oil containingan effective quantity of a hydrogenation catalyst, the hydrogenationcatalyst containing one or more active metal components selected fromPt, Pd, Re and a combination comprising at least two of Pt, Pd or Re,and including a catalyst support comprising non-acidic amorphous aluminaand about 0.1-15 wt% of a modified USY zeolite having one or more of Ti,Zr and/or Hf substituting aluminum atoms constituting the zeoliteframework thereof; and a steam cracking complex operable to thermallycrack the hydrogenated middle distillates for production of lightolefins.